**UNITED STATESSECURITIES AND EXCHANGE COMISSION**

**Washington,D.C. 20549**

**FORM 10-Q**

**x**                              QUARTERLYREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934

**Forthe quarterly period ended September 30, 2006**

**OR**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934

**Forthe transition period from                  to                  **

**Commissionfile number 1-10934**

**ENBRIDGE ENERGY PARTNERS, L.P.**

(Exact name of registrantas specified in its charter)

| **Delaware**                                                     |   | **39-1715850**                        |
|------------------------------------------------------------------|--------|---------------------------------------|
| (State or other  jurisdiction of  incorporation or organization) |   | (I.R.S. Employer  Identification No.) |
| **1100 Louisiana  Suite 3300  Houston, TX 77002**           |
| (Address of  principal executive offices and zip code)           |
| **(713) 821-2000**                                               |
| (Registrant’s  telephone number, including area code)       |

 

Indicate by check markwhether the registrant: (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes  x  No o

Indicate by check markwhether the registrant is a large accelerated filer, accelerated filer, or anon-accelerated filer (as defined in Rule  12b-2 of theExchange Act). Large Accelerated Filer xAccelerated Filer o Non-AcceleratedFiler o

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2of the Exchange Act). Yes o  No x

TheRegistrant had 49,938,834 Class A common units outstanding as of October 30,2006.

 

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**TABLEOF CONTENTS**
|                | ** ** | **PART I.  FINANCIAL INFORMATION**                                                                                               | ** ** | ** ** |
|----------------|------------|---------------------------------------------------------------------------------------------------------------------------------------|------------|------------|
| Item  1.       |       | Financial  Statements                                                                                                                 |       | 3          |
|           |       | Consolidated Statements of Income for the three and  nine month periods ended September 30, 2006 and 2005                        |       | 3          |
|           |       | Consolidated Statements of Comprehensive Income for  the three and nine month periods ended September 30, 2006 and 2005          |       | 4          |
|           |       | Consolidated Statements of Cash Flows for the nine  month periods ended September 30, 2006 and 2005                              |       | 5          |
|           |       | Consolidated Statements of Financial Position as of  September 30, 2006 and December 31, 2005      |       | 6          |
|           |       | Notes to Consolidated Financial Statements                                                                                            |       | 7          |
| Item 2.        |       | Management’s Discussion and Analysis of Financial  Condition and Results of Operations                                           |       | 17         |
| Item 3.        |       | Quantitative and Qualitative Disclosures About Market  Risk                                                                           |       | 35         |
| Item 4.        |       | Controls and Procedures                                                                                                               |       | 41         |
| ** **     | ** ** | **PART II.  OTHER INFORMATION**                                                                                                  |       |       |
| Item  1.       |       | Legal  Proceedings                                                                                                                    |       | 42         |
| Item 1A.       |       | Risk Factors                                                                                                                          |       | 42         |
| Item 6.        |       | Exhibits                                                                                                                              |       | 44         |
| **Signatures** |       | 45                                                                                                                                    |
| **Exhibits**   |       |                                                                                                                                  |

 

*In this report,unless the context requires otherwise, references to “we”, “us”, “our”, or the “Partnership”are intended to mean Enbridge Energy Partners, L.P. and its consolidatedsubsidiaries. This Quarterly Report on Form 10-Q contains forward-lookingstatements. These forward-looking statements are identified as anystatement that does not relate strictly to historical or current facts. Theyuse words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,”“intend,” “may,” “plan,” “position,” “projection,” “strategy,” “could,” “would,”or “will” or the negative of those terms or other variations of them or bycomparable terminology. In particular, statements, expressed or implied,concerning future actions, conditions or events or future operating results orthe ability to generate sales, income or cash flow or to make distributions areforward-looking statements. Forward-looking statements are notguarantees of performance. They involve risks, uncertainties and assumptions.Future actions, conditions or events and future results of operations maydiffer materially from those expressed in these forward-lookingstatements. Many of the factors that will determine these results are beyondour ability to control or predict. For additional discussion of risks,uncertainties and assumptions, see “Risk Factors” included in Part I,Item 1A of our Annual Report on Form 10-K for the fiscal yearended December 31, 2005 and in Part II, Item 1A of ourquarterly reports on Form 10-Q.*

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**PART I—FINANCIALINFORMATION**

**Item 1.**                        FinancialStatements

**ENBRIDGEENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF INCOME**

| ** **                                                               | ** ** | **Three months ended  September 30,**                                | ** ** | **Nine months ended  September 30,** | ** ** |
|--------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                               | ** ** | **2006**                                                                            | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                               | ** ** | **(unaudited; in millions, except per unit amounts)** | ** ** |
|                                                                     |       |                                                                                |       |                                                |       |   |   |   |   |
| Operating revenue                                                        |       | $                                                                                   | 1,532.3    |                                                | $          | 1,809.6 |   | $ | 4,845.6 |   | $ | 4,392.4 |   |
| Operating expenses                                                       |       |                                                                                |       |                                                |       |   |   |   |   |
| Cost of natural gas  (Notes 5 and 10)                                    |       | 1,265.9                                                                             |       | 1,659.8                                             |       | 4,099.2 |   | 3,882.4 |   |
| Operating and  administrative                                            |       | 95.1                                                                                |       | 82.4                                                |       | 256.3 |   | 237.2 |   |
| Power                                                                    |       | 27.8                                                                                |       | 19.0                                                |       | 78.3 |   | 53.2 |   |
| Depreciation and  amortization (Note 6)                                  |       | 34.8                                                                                |       | 36.5                                                |       | 101.5 |   | 103.9 |   |
|                                                                     |       | 1,423.6                                                                             |       | 1,797.7                                             |       | 4,535.3 |   | 4,276.7 |   |
| Operating income                                                         |       | 108.7                                                                               |       | 11.9                                                |       | 310.3 |   | 115.7 |   |
| Interest expense                                                         |       | (28.5                                                                               | )          | (28.4                                               | )          | (84.0 | ) | (79.6 | ) |
| Other income                                                             |       | 2.0                                                                                 |       | 2.1                                                 |       | 7.4 |   | 3.4 |   |
| Net income (loss)                                                        |       | $                                                                                   | 82.2       |                                                | $          | (14.4 | ) | $ | 233.7 |   | $ | 39.5 |   |
| Net income (loss)  allocable to limited partner units  (Note 2)          |       | $                                                                                   | 73.5       |                                                | $          | (19.5 | ) | $ | 210.6 |   | $ | 22.6 |   |
| Net income (loss) per  limited partner unit (basic and diluted) (Note 2) |       | $                                                                                   | 1.03       |                                                | $          | (0.32 | ) | $ | 3.11 |   | $ | 0.37 |   |
| Weighted average units  outstanding                                      |       | 71.7                                                                                |       | 62.1                                                |       | 67.8 |   | 61.5 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**

| ** **                                  | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|---------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                  | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                  | ** ** | **(unaudited; in millions)**               | ** ** |
|                                        |       |                                                 |       |                                                |       |   |   |   |   |
| Net income (loss)                           |       | $                                                    | 82.2       |                                                | $          | (14.4 | ) | $ | 233.7 |   | $ | 39.5 |   |
| Other comprehensive income (loss) (Note 10) |       | 91.8                                                 |       | (138.4                                              | )          | 95.6 |   | (224.1 | ) |
| Comprehensive income (loss)                 |       | $                                                    | 174.0      |                                                | $          | (152.8 | ) | $ | 329.3 |   | $ | (184.6 | ) |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS**

| ** **                                                                         | ** ** | **Nine months ended  September 30,**                  | ** ** |
|------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **     2006     ** | ** ** | **     2005     ** | ** ** |
| ** **                                                                         | ** ** | **(unaudited; in millions)**                               | ** ** |
| Cash provided by operating activities                                              |       |                                                                 |       |   |   |   |   |   |   |
| Net income                                                                         |       |                                                                 | $          | 233.7 |   |   |   | $ | 39.5 |   |   |
| Adjustments to reconcile net income to net cash  provided by operating activities: |       |                                                                 |       |   |   |   |   |   |   |
| Depreciation and  amortization (Note 6)                                            |       |                                                                 | 101.5      |   |   |   | 103.9 |   |   |
| Derivative fair  value (gains) losses (Note 10)                                    |       |                                                                 | (53.1      | ) |   |   | 69.4 |   |   |
| Inventory market  price adjustments (Note 5)                                       |       |                                                                 | 16.7       |   |   |   | — |   |   |
| Other                                                                              |       |                                                                 | 5.1        |   |   |   | (0.1 | ) |   |
| Changes in operating assets and liabilities, net of  cash acquired:                |       |                                                                 |       |   |   |   |   |   |   |
| Receivables,  trade and other                                                      |       |                                                                 | (5.3       | ) |   |   | (13.1 | ) |   |
| Due from General  Partner and affiliates                                           |       |                                                                 | 9.2        |   |   |   | (6.2 | ) |   |
| Accrued  receivables                                                               |       |                                                                 | 236.8      |   |   |   | (338.8 | ) |   |
| Inventory (Note  5)                                                                |       |                                                                 | (56.7      | ) |   |   | (66.2 | ) |   |
| Current and long-term  other assets (Note 10)                                      |       |                                                                 | (3.3       | ) |   |   | (3.3 | ) |   |
| Due to General  Partner and affiliates                                             |       |                                                                 | 2.0        |   |   |   | 13.5 |   |   |
| Accounts payable  and other (Notes 4 and 10)                                       |       |                                                                 | (18.5      | ) |   |   | (2.0 | ) |   |
| Accrued purchases                                                                  |       |                                                                 | (258.5     | ) |   |   | 385.5 |   |   |
| Interest payable                                                                   |       |                                                                 | 19.0       |   |   |   | 24.5 |   |   |
| Property and  other taxes payable                                                  |       |                                                                 | 1.3        |   |   |   | 1.6 |   |   |
| Net cash provided by  operating activities                                         |       |                                                                 | 229.9      |   |   |   | 208.2 |   |   |
| Cash used in investing activities                                                  |       |                                                                 |       |   |   |   |   |   |   |
| Additions to  property, plant and equipment                                        |       |                                                                 | (514.3     | ) |   |   | (261.9 | ) |   |
| Changes in  construction payables                                                  |       |                                                                 | 17.4       |   |   |   | 3.3 |   |   |
| Asset  acquisitions, net of cash acquired (Note 3)                                 |       |                                                                 | (33.3      | ) |   |   | (186.4 | ) |   |
| Other                                                                              |       |                                                                 | 0.4        |   |   |   | 2.7 |   |   |
| Net cash used in  investing activities                                             |       |                                                                 | (529.8     | ) |   |   | (442.3 | ) |   |
| Cash provided by financing activities                                              |       |                                                                 |       |   |   |   |   |   |   |
| Proceeds from  unit issuances, net (Note 8)                                        |       |                                                                 | 509.6      |   |   |   | 127.5 |   |   |
| Distributions to  partners (Note 8)                                                |       |                                                                 | (169.8     | ) |   |   | (157.3 | ) |   |
| Repayments of  Credit Facility, net (Note 7)                                       |       |                                                                 | —     |   |   |   | (175.0 | ) |   |
| Net issuances of  commercial paper (Note 7)                                        |       |                                                                 | 143.9      |   |   |   | 455.0 |   |   |
| Repayment on  affiliate loan                                                       |       |                                                                 | (20.0      | ) |   |   | — |   |   |
| Other                                                                              |       |                                                                 | —     |   |   |   | (1.0 | ) |   |
| Net cash provided by  financing activities                                         |       |                                                                 | 463.7      |   |   |   | 249.2 |   |   |
| Net increase in  cash and cash equivalents                                         |       |                                                                 | 163.8      |   |   |   | 15.1 |   |   |
| Cash and cash  equivalents at beginning of year                                    |       |                                                                 | 89.8       |   |   |   | 78.3 |   |   |
| Cash and cash  equivalents at end of period                                        |       |                                                                 | $          | 253.6 |   |   |   | $ | 93.4 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

5

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF FINANCIAL POSITION**

| ** **                                                                                                 | ** ** | **September 30,  2006**                  | ** ** | **December 31,  2005** | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                 | ** ** | **(unaudited; $ in millions)** | ** ** |
| **ASSETS**                                                                                                 | ** ** |                                          | ** ** | ** **                  |       |   | ** ** | ** ** |   |
| **Current assets**                                                                                         |       |                                          |       |                        |       |   |   |   |   |
| **Cash and cash equivalents (Note  4)**                                                                    |       |                                          | $          | 253.6                       |       |   |   | $ | 89.8 |   |   |
| **Receivables, trade and other, net  of allowance for doubtful accounts of $4.0 in 2006 and $4.5 in 2005** |       |                                          | 114.9      |                        |       |   | 109.7 |   |   |
| **Due from General Partner and  affiliates**                                                               |       |                                          | 10.9       |                        |       |   | 20.1 |   |   |
| **Accrued receivables**                                                                                    |       |                                          | 378.5      |                        |       |   | 615.3 |   |   |
| **Inventory (Note 5)**                                                                                     |       |                                          | 175.9      |                        |       |   | 138.9 |   |   |
| **Other current assets (Note 10)**                                                                         |       |                                          | 12.7       |                        |       |   | 11.5 |   |   |
| ** **                                                                                                 |       |                                          | 946.5      |                        |       |   | 985.3 |   |   |
| **Property, plant and equipment,  net (Notes 3 and 6)**                                                    |       |                                          | 3,509.6    |                        |       |   | 3,080.0 |   |   |
| **Other assets, net (Note 10)**                                                                            |       |                                          | 24.3       |                        |       |   | 22.2 |   |   |
| **Goodwill (Note 3)**                                                                                      |       |                                          | 265.7      |                        |       |   | 258.2 |   |   |
| **Intangibles, net (Note 3)**                                                                              |       |                                          | 92.4       |                        |       |   | 82.7 |   |   |
| ** **                                                                                                 |       |                                          | $          | 4,838.5                     |       |   |   | $ | 4,428.4 |   |   |
| **LIABILITIES AND  PARTNERS’ CAPITAL**                                                                | ** ** |                                          | ** ** | ** **                  |       |   | ** ** | ** ** |   |
| **Current  liabilities**                                                                                   |       |                                          |       |                        |       |   |   |   |   |
| **Due to General Partner and  affiliates**                                                                 |       |                                          | $          | 14.5                        |       |   |   | $ | 12.5 |   |   |
| **Accounts payable and other (Notes  4 and 10)**                                                           |       |                                          | 183.0      |                        |       |   | 247.9 |   |   |
| **Accrued purchases**                                                                                      |       |                                          | 388.2      |                        |       |   | 646.7 |   |   |
| **Interest payable**                                                                                       |       |                                          | 28.8       |                        |       |   | 11.4 |   |   |
| **Property and other taxes payable**                                                                       |       |                                          | 22.2       |                        |       |   | 21.8 |   |   |
| **Current maturities of long-term  debt**                                                                  |       |                                          | 31.0       |                        |       |   | 31.0 |   |   |
| ** **                                                                                                 |       |                                          | 667.7      |                        |       |   | 971.3 |   |   |
| **Long-term debt (Note 7)**                                                                                |       |                                          | 1,827.4    |                        |       |   | 1,682.9 |   |   |
| **Loans from General Partner and  affiliates**                                                             |       |                                          | 134.0      |                        |       |   | 151.8 |   |   |
| **Environmental liabilities (Note  9)**                                                                    |       |                                          | 4.2        |                        |       |   | 4.8 |   |   |
| **Other long-term liabilities (Note  10)**                                                                 |       |                                          | 172.3      |                        |       |   | 253.8 |   |   |
| ** **                                                                                                 |       |                                          | 2,805.6    |                        |       |   | 3,064.6 |   |   |
| **Commitments  and contingencies (Note 9)**                                                                |       |                                          |       |                        |       |   |   |   |   |
| **Partners’  capital (Note 8)**                                                                       |       |                                          |       |                        |       |   |   |   |   |
| **Class A common units (Units  issued—49,938,834 in 2006 and 2005)**                             |       |                                          | 1,159.9    |                        |       |   | 1,142.4 |   |   |
| **Class B common units (Units  issued—3,912,750 in 2006 and 2005)**                              |       |                                          | 68.9       |                        |       |   | 67.2 |   |   |
| **Class C units (Units  issued—10,869,565 in 2006)**                                             |       |                                          | 503.7      |                        |       |   | — |   |   |
| **i-units (Units issued—12,440,455  in 2006 and 11,704,948 in 2005)**                                 |       |                                          | 459.3      |                        |       |   | 421.7 |   |   |
| **General Partner**                                                                                        |       |                                          | 47.6       |                        |       |   | 34.6 |   |   |
| **Accumulated other comprehensive  loss (Note 10)**                                                        |       |                                          | (206.5     | )                           |       |   | (302.1 | ) |   |
| ** **                                                                                                 |       |                                          | 2,032.9    |                        |       |   | 1,363.8 |   |   |
| ** **                                                                                                 |       |                                          | $          | 4,838.5                     |       |   |   | $ | 4,428.4 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)**

**1.**                 BASISOF PRESENTATION

The accompanying unauditedinterim consolidated financial statements have been prepared in accordance withaccounting principles generally accepted in the United States of America forinterim consolidated financial information and with the instructions to Form 10-Qand Rule 10-01 of Regulation S-X. Accordingly, they donot include all the information and footnotes required by accounting principlesgenerally accepted in the United States of America for complete consolidatedfinancial statements. In the opinion of management, they contain alladjustments, consisting only of normal recurring adjustments, which managementconsiders necessary to present fairly the financial position as of September 30,2006 and December 31, 2005; the results of operations for the three andnine month periods ended September 30, 2006 and 2005; and cash flows forthe nine month periods ended September 30, 2006 and 2005. The results ofoperations for the three and nine month periods ended September 30, 2006,should not be taken as indicative of the results to be expected for the fullyear due to seasonality of portions of the natural gas business, maintenanceactivities and the impact of forward natural gas prices on certain derivativefinancial instruments that are accounted for using mark-to-marketaccounting. In addition, prior period information presented in theseconsolidated financial statements includes reclassifications that were made toconform to the current period presentation. These reclassifications have noeffect on previously reported net income or partners’ capital. The interimconsolidated financial statements should be read in conjunction with ourconsolidated financial statements and notes presented in our Annual Report on Form 10-Kfor the fiscal year ended December 31, 2005.

**2.**                 NETINCOME PER LIMITED PARTNER UNIT

Netincome per limited partner unit is computed by dividing net income, afterdeduction of Enbridge Energy Company, Inc.’s (the “General Partner”)allocation, by the weighted average number of our limited partner unitsoutstanding. The General Partner’s allocation is equal to an amount based uponits general partner interest, adjusted to reflect an amount equal to itsincentive distributions and an amount required to reflect depreciation on theGeneral Partner’s historical cost basis for assets contributed on formation ofthe Partnership. We have no dilutive securities. Net income per limited partnerunit was determined as follows:

| ** **                                                      | ** ** | **Three months ended  September 30,**                | ** ** | **Nine months ended  September 30,** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                      | ** ** | **   2006   **                        | ** ** | **   2005   **        | ** ** | **   2006   ** | ** ** | **   2005   ** | ** ** |
| ** **                                                      | ** ** | **(in millions, except per unit amounts)** | ** ** |
| Net income (loss)                                               |       |                                                                | $          | 82.2                                                |       |   |   | $ | (14.4 | ) |   |   | $ | 233.7 |   |   |   | $ | 39.5 |   |   |
| Allocations to the General Partner:                             |       |                                                                |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Net (income) loss  allocated to General Partner                 |       |                                                                | (1.7       | )                                                   |       |   | 0.3 |   |   |   | (4.7 | ) |   |   | (0.8 | ) |   |
| Incentive  distributions to General Partner                     |       |                                                                | (7.0       | )                                                   |       |   | (5.4 | ) |   |   | (18.3 | ) |   |   | (16.0 | ) |   |
| Historical cost  depreciation adjustments                       |       |                                                                | —     |                                                |       |   | — |   |   |   | (0.1 | ) |   |   | (0.1 | ) |   |
|                                                            |       |                                                                | (8.7       | )                                                   |       |   | (5.1 | ) |   |   | (23.1 | ) |   |   | (16.9 | ) |   |
| Net income (loss)  allocable to limited partner units           |       |                                                                | $          | 73.5                                                |       |   |   | $ | (19.5 | ) |   |   | $ | 210.6 |   |   |   | $ | 22.6 |   |   |
| Weighted average  units outstanding                             |       |                                                                | 71.7       |                                                |       |   | 62.1 |   |   |   | 67.8 |   |   |   | 61.5 |   |   |
| Net income (loss)  per limited partner unit (basic and diluted) |       |                                                                | $          | 1.03                                                |       |   |   | $ | (0.32 | ) |   |   | $ | 3.11 |   |   |   | $ | 0.37 |   |   |

 

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**3.**                 ACQUISITIONS

In April 2006, we acquired, for $33.3 million incash, an 80-mile natural gas pipeline that is complementary to ourexisting East Texas system. This pipeline provides approximately 100 millioncubic feet per day, or MMcf/d, of additional transportation capacity andinterconnects with approximately 65 central delivery points.

Thepurchase price and the allocation to assets acquired and liabilities assumedare as follows in millions of dollars:

| Purchase Price:                                                    |   |   |   |
|--------------------------------------------------------------------|--------|--------|--------|
| Cash paid,  including transaction costs                            |   | $      | 33.3   |   |
| Allocation of purchase price:                                      |   |   |   |
| Property, plant  and equipment, including construction in progress |   | 13.0   |   |
| Intangibles                                                        |   | 12.8   |   |
| Goodwill                                                           |   | 7.5    |   |
| Total                                                              |   | $      | 33.3   |   |

 

**4.**                 CASHAND CASH EQUIVALENTS

We extinguish liabilitieswhen a creditor has relieved us of our obligation, which occurs when ourfinancial institution honors a check that the creditor has presented forpayment. Accordingly, obligations for which we have issued check payments thathave not yet been presented to the financial institution of approximately$34.8 million at September 30, 2006 and $46.5 million at December 31,2005, are included in Accounts payable and other on our Consolidated Statementsof Financial Position.

**5.**                 INVENTORY

Inventoryis comprised of the following:

| ** **                                    | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|-----------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                    | ** ** | **(in millions)**       | ** ** |
| Material and supplies                         |       |                         | $          | 4.3                         |       |   |   | $ | 8.3 |   |   |
| Liquids inventory                             |       |                         | 16.9       |                        |       |   | 11.1 |   |   |
| Natural gas and natural gas liquids inventory |       |                         | 154.7      |                        |       |   | 119.5 |   |   |
|                                          |       |                         | $          | 175.9                       |       |   |   | $ | 138.9 |   |   |

 

Our inventory includescharges totaling $16.7 million, of which $7.0 million was recorded in thecurrent quarter, to reduce the cost basis of our natural gas inventory toreflect market value. The lower of cost or market adjustments are included inthe Cost of natural gas of our Natural Gas and Marketing segments on ourConsolidated Statements of Income.

**6.**                 PROPERTY,PLANT AND EQUIPMENT

Based on a third-partystudy commissioned by management, revised depreciation rates for the Lakeheadsystem were implemented effective January 1, 2006. The annual compositerate, which represents the expected remaining service life of the Lakeheadsystem assets, was reduced from 3.20% to 2.63%. Depreciation expense wasapproximately $2.8 million and $8.3 million lower for the three and nine monthsended September 30, 2006, respectively, as a result of the newdepreciation rates.

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**7.**                 DEBT

***Credit Facility***

In March 2006, we obtained an increase from $800million to $1 billion in the aggregate commitment available to us under theterms of our Credit Facility. At September 30, 2006 and December 31,2005, we had no amounts outstanding under our Credit Facility. We had lettersof credit totaling $59.1 million at September 30, 2006, and $149.3million at December 31, 2005. The amounts we may borrow under the terms ofour Credit Facility are reduced by the principal amount of our commercial paperissuances and the balance of our letters of credit outstanding. At September 30,2006, we could borrow an additional $465.9 million under the terms of ourCredit Facility.

During the nine monthsended September 30, 2005, we net settled borrowings of approximately $565million on a non-cash basis.

***Commercial Paper Program***

We can issue up to $600million in principal amount of commercial paper under the terms of ourcommercial paper program. However, the amount of commercial paper we may issueis reduced by any balance of outstanding letters of credit in excess of $400million. At September 30, 2006, we had $473.8 million of commercial paperoutstanding, net of unamortized discount of $1.2 million, bearing interest at aweighted average rate of 5.55%. At December 31, 2005, we had$329.3 million of commercial paper outstanding, net of $0.7 millionof unamortized discount, at a weighted average interest rate of 4.36%. At September 30,2006, we could issue an additional $125 million in principal amount under ourcommercial paper program.

**8.**                 PARTNERS’CAPITAL

The followingtable sets forth our distributions, as approved by the Board of Directors ofEnbridge Energy Management, L.L.C. (“Enbridge Management”), during the ninemonths ended September 30, 2006:

| **Distribution  Declaration  Date** | ** ** | **Distribution  Payment Date** | ** ** | **Record  Date**       | ** ** | **Distribution  per Unit** | ** ** | **Cash  available for  distribution** | ** ** | **Amount of  Distribution  of i-units  to i-unit  Holders**(1) | ** ** | **Retained  from  General  Partner**(2) | ** ** | **Distribution  of Cash** | ** ** |
|-------------------------------------|------------|-------------------------------------|------------|------------------------|------------|---------------------------------|------------|--------------------------------------------|------------|-------------------------------------------------------------------------------|------------|-----------------------------------------|------------|--------------------------------|------------|
| January 30,  2006              |       | February 14,  2006             |       | February 7,  2006 |       |                            | $          | 0.925                                      |       |                                                                          |       | $                                       | 67.6       |                           |       |   | $ | 10.8 |   |   |   | $ | 0.2 |   |   |   | $ | 56.6 |   |   |
| April 27,  2006                |       | May 15,  2006                  |       | May 5,  2006      |       |                            | $          | 0.925                                      |       |                                                                          |       | $                                       | 67.8       |                           |       |   | $ | 11.0 |   |   |   | $ | 0.2 |   |   |   | $ | 56.6 |   |   |
| July 28, 2006                  |       | August 14, 2006                |       | August 4, 2006    |       |                            | $          | 0.925                                      |       |                                                                          |       | $                                       | 68.1       |                           |       |   | $ | 11.3 |   |   |   | $ | 0.2 |   |   |   | $ | 56.6 |   |   |

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(1)                 We have issued 735,507 i-units to EnbridgeManagement, the sole owner of the Partnership’s i-units, during 2006 in lieu ofcash distributions.

(2)                 We retain an amount equal to 2% of the i-unitdistribution from the General Partner to maintain its 2% general partnerinterest.

***Private Placement of Class C Units***

On August 15, 2006, we issued and sold 5.4million Class C units, representing a new class of limited partnerinterest, to our general partner and 5.4 million Class C units to aninstitutional investor for a purchase price of $46.00 per unit in a privatetransaction exempt from registration under Section 4(2) of theSecurities Act of 1933. We received proceeds of approximately $500 million, netof expenses associated with the private placement. Additionally, our generalpartner contributed approximately $10 million to maintain its two percentgeneral partner interest.

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Until August 15, 2009, in lieu of cashdistributions, the holders of our Class C units will receive quarterlydistributions of additional Class C units with a value equal to thequarterly cash distributions we pay to the holders of our Class A and Class Bcommon units, which we collectively refer to as common units. The number ofadditional Class C units we will issue is determined by dividing thequarterly cash distribution per unit we pay on our common units by the averagemarket price of a Class A common unit as listed on the New York StockExchange for the 10-trading day period immediately preceding theex-dividend date for our Class A common units multiplied by the number of Class Cunits outstanding on the record date.

After August 15,2009, the holders of our Class C units will receive quarterly cashdistributions equal to those paid to the holders of our common units. Subjectto the approval of holders of our outstanding units in accordance with thethen-existing requirements of the principal national securities exchange onwhich the Class A common units are listed, the Class C units willconvert into Class A common units on a one-for-one basis. If ourunitholders do not approve the conversion, the holders of our Class Cunits will receive quarterly cash distributions equal to 115 percent of thosepaid to the holders of our common units. Prior to conversion, holders of our Class Cunits will not be entitled to receive any quarterly cash distribution until theholders of our common units have received a quarterly cash distribution of$0.59 per common unit.

**9.**                 COMMITMENTS,CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

***Environmental Liabilities***

We are subject to federal and state laws andregulations relating to the protection of the environment. Environmental riskis inherent to liquid and natural gas pipeline operations and we could, attimes, be subject to environmental cleanup and enforcement actions. We managethis environmental risk through appropriate environmental policies andpractices to minimize any impact on the environment of our pipeline operations.

As of September 30, 2006 and December 31,2005, we have recorded $3.0 million and $4.0 million, respectively, incurrent liabilities and $4.2 million and $4.8 million, respectively,in long-term liabilities, primarily to address remediation ofcontaminated sites, materials containing asbestos, management of hazardouswaste material disposal, and outstanding air quality measures for certain ofour liquids and natural gas assets.

In April 2006, anatural gas release and fire near a valve site on our MidLa natural gastransmission pipeline in Concordia Parish, Louisiana, resulted in property andequipment damage in the area. We estimate our losses from this incident toapproximate $1 million, which we recognized in the second quarter of 2006. Wehave not revised our estimate subsequent to the second quarter of 2006.

***Legal Proceedings***

We are a participant invarious legal proceedings arising in the ordinary course of business. Some ofthese proceedings are covered, in whole or in part, by insurance. We believethat the outcome of all these proceedings will not, individually or in theaggregate, have a material adverse effect on our financial condition.

**10.**          FINANCIALINSTRUMENTS—COMMODITY PRICE RISK

Our net income and cashflows are subject to volatility stemming from changes in commodity prices ofnatural gas, natural gas liquids (“NGL” or “NGLs”), condensate and fractionationmargins (the relative price differential between NGL sales and the offsettingnatural gas purchases). This market price exposure exists within our NaturalGas and Marketing segments. To mitigate the volatility of our cash flows, weuse 

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derivativefinancial instruments (i.e., futures, forwards, swaps, options and otherfinancial instruments with similar characteristics) to manage the risksassociated with market fluctuations in commodity prices. Based on our riskmanagement policies, all of our derivative financial instruments are employedin connection with an underlying asset, liability and/or forecasted transactionand are not entered into with the objective of speculating on commodity prices.

***Accounting Treatment***

All derivative financial instruments are recorded inthe consolidated financial statements at fair market value and are adjustedeach period for changes in the fair market value (“mark-to-market”).The fair market value of these derivative financial instruments reflects theestimated amounts that we would pay or receive, other than in a forced orliquidation sale, to terminate or close the contracts at the reporting date,taking into account the current unrealized losses or gains on open contracts.We use actively traded external market quotes and indices to valuesubstantially all of the financial instruments we utilize.

Under the guidance of Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities* (“SFAS No. 133”),if a derivative financial instrument does not qualify as a hedge, or is notdesignated as a hedge, the derivative is adjusted to its fair market value, ormarked-to-market, each period with the increases and decreases infair value recorded as increases and decreases in Cost of natural gas in ourConsolidated Statements of Income. Cash flow is only impacted to the extent theactual derivative contract is settled by making or receiving a payment to orfrom the counterparty or by making or receiving a payment for entering into acontract that exactly offsets the original derivative contract. Typically, wesettle our derivative contracts when the physical transaction that underliesthe derivative financial instrument occurs.

If a derivative financialinstrument qualifies and is designated as a cash flow hedge, a hedge of aforecasted transaction or future cash flows, any unrealized mark-to-market gainor loss is deferred in Accumulated other comprehensive income (“OCI”), acomponent of Partners’ Capital, until the underlying hedged transaction occurs.To the extent that the hedge instrument is effective in offsetting thetransaction being hedged, there is no impact to the income statement. Atinception and on a quarterly basis, we formally assess whether the hedgecontract is highly effective in offsetting changes in cash flows of hedgeditems. Any ineffective portion of a cash flow hedge’s change in fair marketvalue is recognized each period in earnings. Realized gains and losses onderivative financial instruments that are designated as hedges and qualify forhedge accounting are included in Cost of natural gas in the period the hedgedtransaction occurs. Gains and losses deferred in OCI related to cash flowhedges for which hedge accounting has been discontinued, remain in OCI untilthe underlying physical transaction occurs unless it is probable that theforecasted transaction will not occur by the end of the originally specifiedtime period or within an additional two-month period of time thereafter.Generally, our preference is for our derivative financial instruments toreceive hedge accounting treatment whenever possible, to mitigate the non-cashearnings volatility that arises under mark-to-market accountingtreatment. To qualify for cash flow hedge accounting as set forth in SFAS No. 133,very specific requirements must be met in terms of hedge structure, hedgeobjective and hedge documentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have four primary transaction types where the hedge structure doesnot meet the requirements to apply hedge accounting and, therefore, thesederivative financial instruments do not qualify for hedge accounting under SFASNo. 133 and are referred to as “non-qualified.” These non-qualifiedderivative financial instruments are marked-to-market each periodwith the change in fair value, representing unrealized gains and losses,included in Cost of natural gas in our 

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Consolidated Statements ofIncome. These mark-to-market adjustments produce a degree ofearnings volatility that can often be significant from period to period, buthave no cash flow impact relative to changes in market prices. The cash flowimpact occurs when the underlying physical transaction takes place in thefuture and when the associated financial instrument contract settlement ismade.

The four primarytransaction types that do not qualify for hedge accounting are as follows:

1.                **Transportation—**In our Marketing segment, when we transportnatural gas from one location to another the pricing index used for natural gassales is usually different from the pricing index used for natural gaspurchases, which exposes us to market price risk relative to changes in thosetwo indices. By entering into a basis swap, where we exchange one pricing indexfor another, we can effectively lock in the margin, representing the differencebetween the sales price and the purchase price, on the combined natural gaspurchase and natural gas sale, removing any market price risk on the physicaltransactions. Although this represents a sound economic hedging strategy, thederivative financial instruments (i.e., the basis swaps) we use to manage thecommodity price risk associated with these transportation contracts do notqualify for hedge accounting under SFAS No. 133, since only the futuremargin has been fixed and not the future cash flow. As a result, thesederivative financial instruments are marked-to-market.

2.                **Storage—**In our Marketing segment, we use derivativefinancial instruments (i.e., natural gas swaps) to hedge the relativedifference between the injection price paid to purchase and store natural gasand the withdrawal price at which the natural gas is sold from storage. The intentof these derivative financial instruments is to lock in the margin,representing the difference between the price paid for the natural gas injectedand the price received upon withdrawal of the gas from storage in a futureperiod. We do not pursue cash flow hedge accounting treatment for these storagetransactions since the underlying forecasted injection or withdrawal of naturalgas may not occur in the period as originally forecast. This can occur becausewe have the flexibility to make changes in the underlying injection orwithdrawal schedule, given changes in market conditions. In addition, since thephysical natural gas is recorded at the lower of cost or market, timingdifferences can result when the derivative financial instrument is settled in aperiod that is different from when the physical natural gas is sold fromstorage. As a result, derivative financial instruments associated with ournatural gas storage activities can create volatility in our earnings.

3.                **Natural Gas Collars—**In our Natural Gas segment, we hadpreviously entered into natural gas collars to hedge the sales price of naturalgas. The natural gas collars were based on a NYMEX price, while the physicalgas sales were based on a different index. To better align the index of the naturalgas collars with the index of the underlying sales, we de-designated theoriginal cash flow hedging relationship with the intent of contemporaneously re-designatingthe natural gas collars as hedges of forecasted physical natural gas sales witha NYMEX pricing index to better match the indices. However, because the fairvalue of these derivative instruments was a liability to us at re-designation,they are considered net written options under SFAS No. 133 and do notqualify for hedge accounting. These derivatives are being marked-to-market,with the changes in fair value from the date of de-designation recordedto earnings each period. As a result, our operating income will be subject togreater volatility due to movements in the prices of natural gas until theunderlying long-term transactions are settled.

4.                **Optional Natural Gas Processing Volumes—**In our Natural Gassegment we use derivative financial instruments to hedge the volumes of NGLsproduced from our natural gas processing facilities. Our natural gas contractsallow us the option of processing natural gas when it is economical, andceasing to do so when processing becomes uneconomic. We have entered intoderivative financial instruments to fix the sales price of a portion of theNGLs that we produce at our discretion and to fix the associated purchases ofnatural gas required for processing. We will 

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designate derivativefinancial instruments associated with NGLs we produce at our discretion as cashflow hedges when the processing of natural gas is probable of occurrence. However,we are precluded from designating the derivative financial instruments enteredto manage the respective commodity price risk when we are unable to accuratelyforecast the NGLs to be processed at our discretion. As a result, our operatingincome will be subject to increased volatility due to fluctuations in NGLprices until the underlying transactions are settled or offset.

In each of the instances described above, theunderlying physical purchase, storage and sale of natural gas and NGLs areaccounted for on a historical cost or market basis rather than on themark-to-market basis we utilize for the derivative financial instrumentsemployed to mitigate the commodity price risk associated with our storage andtransportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair marketvalue while the physical transactions are recorded at historical cost) canand has resulted in volatility in our reported net income, even though theeconomic margin is essentially unchanged from the date the transactions wereconsummated.

Thefollowing table presents the mark-to-market gains and losses associated withchanges in the fair value of our commodity price derivative financial instruments,which are recorded as an element of Cost of natural gas in our ConsolidatedStatements of Income and disclosed as a reconciling item on our Statements ofCash Flows:

| ** **                                                   | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                           | ** ** | **2006**                                            | ** ** | **2005** | ** ** | **  2006  ** | ** ** | **  2005  ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                               | ** ** |
| Natural Gas segment                                          |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |
| Hedge  ineffectiveness                                       |       |                                                 | $          | (1.4                                                | )          |   | $ | 0.1 |   |   | $ | (1.5 | ) |   | $ | (1.9 | ) |
| Non-qualified  hedges                                        |       |                                                 | 3.2        |                                                |       | (9.6 | ) |   | 1.4 |   |   | (20.7 | ) |
| Marketing                                                    |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |
| Non-qualified  hedges                                        |       |                                                 | 21.9       |                                                |       | (43.1 | ) |   | 53.2 |   |   | (37.8 | ) |
| Discontinued  hedges                                         |       |                                                 | —     |                                                |       | — |   |   | — |   |   | (9.0 | ) |
| Derivative fair value  gains (losses)                        |       |                                                 | $          | 23.7                                                |       |   | $ | (52.6 | ) |   | $ | 53.1 |   |   | $ | (69.4 | ) |
|                                                              |            |                                                      |            |                                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

We record the change in fair value of our cash flowhedges in OCI until the derivative financial instruments are settled, at whichtime they are reclassified from OCI to earnings. Also included in OCI areunrecognized losses of approximately $5.6 million associated with cashflow hedges that were subsequently de-designated. These losses are reclassifiedto earnings over the periods during which the originally hedged forecastedtransactions affect earnings. For the three and nine months ended September 30,2006, we reclassified losses of $24.0 million and $63.7 million, respectivelyfrom OCI to Cost of natural gas on our Consolidated Statements of Income forthe fair value of derivative financial instruments that were settled.

Ourderivative financial instruments are included at their fair values in theConsolidated Statements of Financial Position as follows:

| ** **                   | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**       | ** ** |
| Other current  assets        |       |                         | $          | 5.9                         |       |   |   | $ | 5.8 |   |   |
| Other assets, net            |       |                         | 5.9        |                        |       |   | 4.2 |   |   |
| Accounts payable  and other  |       |                         | (64.2      | )                           |       |   | (129.2 | ) |   |
| Other long-term  liabilities |       |                         | (161.3     | )                           |       |   | (243.0 | ) |   |
|                         |       |                         | $          | (213.7                      | )          |   |   | $ | (362.2 | ) |   |

 

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The decrease in our obligation associated withderivative activities is primarily due to the decline in current and forwardnatural gas prices from December 31, 2005 to September 30, 2006. ThePartnership’s portfolio of derivative financial instruments is largelycomprised of long-term fixed price natural gas sales and purchaseagreements.

We do not requirecollateral or other security from the counterparties to our derivativefinancial instruments, all of which were rated “BBB+” or better by the majorcredit rating agencies.

**11.**          SEGMENTINFORMATION

Our business is divided into operating segments,defined as components of the enterprise, about which financial information isavailable and evaluated regularly by our Chief Operating Decision Maker indeciding how resources are allocated and performance is assessed.

Each of ourreportable segments is a business unit that offers different services andproducts that is managed separately, since each business segment requiresdifferent operating strategies. We have segregated our business activities intothree distinct operating segments:

·       Liquids;

·       Natural Gas; and

·       Marketing.

Thefollowing tables present certain financial information about our businesssegments:

| ** **                                     | ** ** | **As of and for the three months ended September 30, 2006** | ** ** |
|------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                                   | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                        | ** ** |
| Total revenue                                  |       | $                                                                                                             | 127.2      |   |   | $ | 1,251.9 |   |   |   | $ | 772.4 |   |   |   | $ | — |   |   | $ | 2,151.5 |   |
| Less: Intersegment  revenue                    |       | —                                                                                                        |       |   | 565.3 |   |   |   | 53.9 |   |   |   | — |   |   | 619.2 |   |
| Operating revenue                              |       | 127.2                                                                                                         |       |   | 686.6 |   |   |   | 718.5 |   |   |   | — |   |   | 1,532.3 |   |
| Cost of natural gas                            |       | —                                                                                                        |       |   | 568.0 |   |   |   | 697.9 |   |   |   | — |   |   | 1,265.9 |   |
| Operating and  administrative                  |       | 36.0                                                                                                          |       |   | 56.9 |   |   |   | 1.1 |   |   |   | 1.1 |   |   | 95.1 |   |
| Power                                          |       | 27.8                                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | 27.8 |   |
| Depreciation and  amortization                 |       | 16.0                                                                                                          |       |   | 18.7 |   |   |   | 0.1 |   |   |   | — |   |   | 34.8 |   |
| Operating income                               |       | 47.4                                                                                                          |       |   | 43.0 |   |   |   | 19.4 |   |   |   | (1.1 | ) |   | 108.7 |   |
| Interest expense                               |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | (28.5 | ) |   | (28.5 | ) |
| Other income                                   |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | 2.0 |   |   | 2.0 |   |
| Net income                                     |       | $                                                                                                             | 47.4       |   |   | $ | 43.0 |   |   |   | $ | 19.4 |   |   |   | $ | (27.6 | ) |   | $ | 82.2 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                                             | 50.8       |   |   | $ | 175.6 |   |   |   | $ | 0.9 |   |   |   | $ | 1.8 |   |   | $ | 229.1 |   |

 

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| ** **                                     | ** ** | **As of and for the three months ended September 30, 2005** | ** ** |
|------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                                   | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                        | ** ** |
| Total revenue                                  |       | $                                                                                                             | 104.1      |   |   | $ | 1,267.5 |   |   |   | $ | 1,162.6 |   |   |   | $ | — |   |   | $ | 2,534.2 |   |
| Less: Intersegment revenue                     |       | —                                                                                                        |       |   | 669.6 |   |   |   | 55.0 |   |   |   | — |   |   | 724.6 |   |
| Operating revenue                              |       | 104.1                                                                                                         |       |   | 597.9 |   |   |   | 1,107.6 |   |   |   | — |   |   | 1,809.6 |   |
| Cost of natural gas                            |       | —                                                                                                        |       |   | 513.9 |   |   |   | 1,145.9 |   |   |   | — |   |   | 1,659.8 |   |
| Operating and administrative                   |       | 36.1                                                                                                          |       |   | 44.3 |   |   |   | 1.4 |   |   |   | 0.6 |   |   | 82.4 |   |
| Power                                          |       | 19.0                                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | 19.0 |   |
| Depreciation and amortization                  |       | 18.3                                                                                                          |       |   | 18.1 |   |   |   | 0.1 |   |   |   | — |   |   | 36.5 |   |
| Operating income                               |       | 30.7                                                                                                          |       |   | 21.6 |   |   |   | (39.8 | ) |   |   | (0.6 | ) |   | 11.9 |   |
| Interest expense                               |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | (28.4 | ) |   | (28.4 | ) |
| Other income                                   |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | 2.1 |   |   | 2.1 |   |
| Net income (loss)                              |       | $                                                                                                             | 30.7       |   |   | $ | 21.6 |   |   |   | $ | (39.8 | ) |   |   | $ | (26.9 | ) |   | $ | (14.4 | ) |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                             | 17.3       |   |   | $ | 69.2 |   |   |   | $ | — |   |   |   | $ | 0.7 |   |   | $ | 87.2 |   |

 

| ** **                                    | ** ** | **As of and for the nine months ended September 30, 2006** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------|------------|
| ** **                                    | ** ** | **Liquids**                                                                                                  | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                    | ** ** | **(in millions)**                                                                                       | ** ** |
| Total revenue                                 |       | $                                                                                                            | 374.7      |   |   | $ | 4,085.1 |   |   |   | $ | 2,406.4 |   |   |   | $ | — |   |   | $ | 6,866.2 |   |
| Less: Intersegment revenue                    |       | —                                                                                                       |       |   | 1,854.0 |   |   |   | 166.6 |   |   |   | — |   |   | 2,020.6 |   |
| Operating revenue                             |       | 374.7                                                                                                        |       |   | 2,231.1 |   |   |   | 2,239.8 |   |   |   | — |   |   | 4,845.6 |   |
| Cost of natural gas                           |       | —                                                                                                       |       |   | 1,908.4 |   |   |   | 2,190.8 |   |   |   | — |   |   | 4,099.2 |   |
| Operating and administrative                  |       | 99.7                                                                                                         |       |   | 150.6 |   |   |   | 3.7 |   |   |   | 2.3 |   |   | 256.3 |   |
| Power                                         |       | 78.3                                                                                                         |       |   | — |   |   |   | — |   |   |   | — |   |   | 78.3 |   |
| Depreciation and amortization                 |       | 47.8                                                                                                         |       |   | 53.2 |   |   |   | 0.3 |   |   |   | 0.2 |   |   | 101.5 |   |
| Operating income                              |       | 148.9                                                                                                        |       |   | 118.9 |   |   |   | 45.0 |   |   |   | (2.5 | ) |   | 310.3 |   |
| Interest expense                              |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | (84.0 | ) |   | (84.0 | ) |
| Other income                                  |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | 7.4 |   |   | 7.4 |   |
| Net income                                    |       | $                                                                                                            | 148.9      |   |   | $ | 118.9 |   |   |   | $ | 45.0 |   |   |   | $ | (79.1 | ) |   | $ | 233.7 |   |
| Total assets                                  |       | $                                                                                                            | 1,752.4    |   |   | $ | 2,584.1 |   |   |   | $ | 264.6 |   |   |   | $ | 237.4 |   |   | $ | 4,838.5 |   |
| Capital expenditures (excluding acquisitions) |       | $                                                                                                            | 101.6      |   |   | $ | 404.7 |   |   |   | $ | 1.8 |   |   |   | $ | 6.2 |   |   | $ | 514.3 |   |

 

| ** **                                     | ** ** | **As of and for the nine months ended September 30, 2005** | ** ** |
|------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                                  | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                       | ** ** |
| Total revenue                                  |       | $                                                                                                            | 303.1      |   |   | $ | 3,180.1 |   |   |   | $ | 2,658.5 |   |   |   | $ | — |   |   | $ | 6,141.7 |   |
| Less: Intersegment revenue                     |       | —                                                                                                       |       |   | 1,635.3 |   |   |   | 114.0 |   |   |   | — |   |   | 1,749.3 |   |
| Operating revenue                              |       | 303.1                                                                                                        |       |   | 1,544.8 |   |   |   | 2,544.5 |   |   |   | — |   |   | 4,392.4 |   |
| Cost of natural gas                            |       | —                                                                                                       |       |   | 1,299.9 |   |   |   | 2,582.5 |   |   |   | — |   |   | 3,882.4 |   |
| Operating and administrative                   |       | 105.5                                                                                                        |       |   | 126.3 |   |   |   | 3.1 |   |   |   | 2.3 |   |   | 237.2 |   |
| Power                                          |       | 53.2                                                                                                         |       |   | — |   |   |   | — |   |   |   | — |   |   | 53.2 |   |
| Depreciation and amortization                  |       | 53.6                                                                                                         |       |   | 49.9 |   |   |   | 0.4 |   |   |   | — |   |   | 103.9 |   |
| Operating income                               |       | 90.8                                                                                                         |       |   | 68.7 |   |   |   | (41.5 | ) |   |   | (2.3 | ) |   | 115.7 |   |
| Interest expense                               |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | (79.6 | ) |   | (79.6 | ) |
| Other income                                   |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | 3.4 |   |   | 3.4 |   |
| Net income                                     |       | $                                                                                                            | 90.8       |   |   | $ | 68.7 |   |   |   | $ | (41.5 | ) |   |   | $ | (78.5 | ) |   | $ | 39.5 |   |
| Total assets                                   |       | $                                                                                                            | 1,672.8    |   |   | $ | 2,239.4 |   |   |   | $ | 557.4 |   |   |   | $ | 91.4 |   |   | $ | 4,561.0 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                                            | 52.0       |   |   | $ | 206.5 |   |   |   | $ | — |   |   |   | $ | 3.4 |   |   | $ | 261.9 |   |

 

15

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**12.**          SUBSEQUENTEVENT

***Distribution to Partners***

On October 27, 2006,the Board of Directors of Enbridge Management declared a distribution payableto our partners on November 14, 2006. The distribution will be paid tounitholders of record as of November 6, 2006, of our available cash of$79.6 million at September 30, 2006, or $0.925 per limited partnerunit. Of this distribution, $57.6 million will be paid in cash,$11.5 million will be distributed in i-units to our i-unitholder,$10.1 will be distributed in Class C units to the holders of our Class Cunits and $0.4 million will be retained from the General Partner inrespect of the i-unit and Class C unit distributions.

**13.**          RECENTACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In September 2006, the Financial AccountingStandards Board (FASB) issued FASB Statement No. 157, *Fair ValueMeasurements*. This statement defines fair value, establishes aframework for measuring fair value in generally accepted accounting principles(GAAP), and expands disclosures about fair value measurement. The statement iseffective for fiscal years beginning after November 15, 2007, and withlimited exceptions is to be applied prospectively as of the beginning of thefiscal year initially adopted. We do not expect our adoption of this pronouncementto materially effect our financial statements. However, adoption of thispronouncement may affect our disclosures regarding derivative financialinstruments and indebtedness.

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**Item 2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations

The following discussion of financial condition andresults of operations of Enbridge Energy Partners, L.P. should be readtogether with the consolidated financial statements and related notes includedin Item 1 of this report. The discussion in this section pertains to ourunaudited consolidated statements of financial position, statements of income,and statements of cash flows included in “Item 1. Financial Statements”of this quarterly report on Form 10-Q.

This quarterly report on Form 10-Qshould be read in conjunction with our annual report on Form 10-Kfor the year ended December 31, 2005.

**RESULTS OFOPERATIONS—OVERVIEW**

We provide servicesto our customers and returns for our unitholders primarily through thefollowing activities:

·       Interstate pipelinetransportation and storage of crude oil and liquid petroleum;

·       Gathering, treating,processing and transportation of natural gas and natural gas liquids, or NGLs,through pipelines and related facilities; and

·       Providing supply, transmissionand sales services, including purchasing and selling natural gas and NGLs.

We conduct our business through three businesssegments: Liquids, Natural Gas and Marketing. These segments are strategicbusiness units established by senior management to facilitate the achievementof our long-term objectives, to aid in resource allocation decisions andto assess operational performance.

We primarily provide fee-based services to ourcustomers to minimize our exposure to commodity price risks. However, in ournatural gas and marketing businesses, a portion of our earnings and cash flowsare exposed to movements in the prices of natural gas and NGLs. Tosubstantially mitigate this exposure and to provide stability to thePartnership’s cash flow, we enter into derivative financial instrumenttransactions. Certain of these transactions qualify for hedge accounting underStatement of Financial Accounting Standards No. 133, *Accounting for Derivative Transactions and HedgingActivities* (“SFAS No. 133”); some, however, must beaccounted for using the mark-to-market method of accounting andthis can expose our earnings to significant volatility.

Thefollowing table reflects our operating income by business segment and corporatecharges for the three and nine month periods ended September 30, 2006 and2005:

| ** **                                  | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|---------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                  | ** ** | **   2006   **         | ** ** | **   2005   **        | ** ** | **  2006  ** | ** ** | **  2005  ** | ** ** |
| ** **                                  | ** ** | **(unaudited; in millions)**               | ** ** |
| **Operating Income**                   | ** ** |                                                 | ** ** | ** **                                          |       |   | ** ** | ** ** |   |   |   | ** ** |   |
| **Liquids**                                 |       |                                                 | $          | 47.4                                                |       |   |   | $ | 30.7 |   |   | $ | 148.9 |   | $ | 90.8 |   |
| **Natural Gas**                             |       |                                                 | 43.0       |                                                |       |   | 21.6 |   |   | 118.9 |   | 68.7 |   |
| **Marketing**                               |       |                                                 | 19.4       |                                                |       |   | (39.8 | ) |   | 45.0 |   | (41.5 | ) |
| **Corporate, operating and administrative** |       |                                                 | (1.1       | )                                                   |       |   | (0.6 | ) |   | (2.5 | ) | (2.3 | ) |
| **Total Operating Income**                  |       |                                                 | 108.7      |                                                |       |   | 11.9 |   |   | 310.3 |   | 115.7 |   |
| **Interest expense**                        |       |                                                 | (28.5      | )                                                   |       |   | (28.4 | ) |   | (84.0 | ) | (79.6 | ) |
| **Other income**                            |       |                                                 | 2.0        |                                                |       |   | 2.1 |   |   | 7.4 |   | 3.4 |   |
| **Net Income (loss)**                       |       |                                                 | $          | 82.2                                                |       |   |   | $ | (14.4 | ) |   | $ | 233.7 |   | $ | 39.5 |   |

 

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***Summary Analysis of Operating Results***

*Liquids*

The increase inoperating income of our Liquids segment for the three and nine month periodsended September 30, 2006, over the comparable periods in 2005 isattributable to the following primary factors:

·       Highervolumes on our Lakehead system following completion of the repair and expansionof a major oil sands plant that was damaged by a fire in early January 2005,partially offset by higher power costs associated with the increased volumes;

·       The annual index rateincrease effective July 1, 2006, which increased our average tariffs; and

·       Longertransportation hauls on our Lakehead system.

*Natural Gas*

The increase inoperating income of our Natural Gas segment for the three and nine month periodsended September 30, 2006, over the comparable periods in 2005 is primarilyattributable to the following:

·       HigherNGL prices in relation to crude oil and natural gas prices contributed tofavorable operating results from our processing assets in addition to theexpanded processing capacity on ourAnadarko system;

·       Growth in average daily volumes on our majornatural gas systems stemming from continued strong drilling activity in areasserved by our natural gas gathering and processing assets; and

·       Improved rates associated with recontracting of supply and additionalfees for services we provide our customers.

*Marketing*

Operating income fromour Marketing segment increased for the three and nine months ended September30, 2006, from operating losses for the comparable periods in 2005 predominantlyas a result of two factors:

·       Unrealized,non-cash mark-to-market gains for the three and nine months ended September 30,2006 of $21.9 million and $53.2 million compared with non-cash mark-to-marketlosses of $43.1 million and $46.8 million for the comparable periods in2005. The gains resulted from the change in market value of our derivativefinancial instruments that do not qualify for hedge accounting. Additionally,in the second quarter of 2005, we recognized approximately $9.0 million oflosses for the discontinuance of hedge accounting for derivative financialinstruments associated with forecasted transactions we determined were notprobable of occurring as set forth in the original hedge documentation;

·       Partially offsetting theunrealized mark-to-market gains is a non-cash charge of $6.6 million for thethree months and $16.3 million for the nine months ended September 30,2006, resulting from a lower of cost or market accounting adjustment to the costbasis of our natural gas inventory. The market price for natural gas in variousstorage locations experienced further decreases during the quarter from theprices at which the inventory was purchased. We expect to recover a majority ofthis charge when the inventory is sold in future quarters, since we havederivative financial instruments that hedge this physical inventory.

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***Derivative Transactions and Hedging Activities***

We record all derivative financial instruments in theconsolidated financial statements at fair market value pursuant to therequirements of SFAS No. 133. For those derivative financial instrumentsthat do not qualify for hedge accounting, all changes in fair market value arerecorded through our Consolidated Statements of Income each period. The fairmarket value of these derivative financial instruments reflects the estimatedamounts that we would pay or receive, other than in a forced or liquidationsale, to terminate or close the contracts at the reporting date, taking intoaccount the current unrealized losses or gains on open contracts.

Consistent with the current year trend of decliningprices, on average natural gas prices declined modestly in the quarter endedSeptember 30, 2006 relative to the second quarter of 2006 and are back atlevels that existed prior to the 2005 hurricane season. Additionally, NGL andcrude oil prices declined in the current quarter reversing a trend ofincreasing prices that began in early 2006. This declining price environmenthas produced net, non-cash mark-to-market gains on the derivative financialinstruments that do not qualify for hedge accounting associated with ourMarketing and Natural Gas businesses.

While the natural gas and NGL pricing environmentcontinues to remain volatile, the mark-to-market gains and losses created bythis volatility do not affect our cash flow. We expect these non-cash gains andlosses to be offset in future quarters as we settle the derivative financialinstruments and the underlying physical transactions.

Thefollowing table presents the non-cash, mark-to-market gains and losses bysegment, associated with our derivative financial instruments for the three andnine month periods ended September 30, 2006 and 2005:

| ** **                                                   | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                           | ** ** | **   2006   **        | ** ** | **   2005   ** | ** ** | **   2006   ** | ** ** | **   2005   ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                               | ** ** |
| **Natural Gas segment**                                      |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Hedge  ineffectiveness**                                   |       |                                                 | $          | (1.4                                                | )          |   |   | $ | 0.1 |   |   |   | $ | (1.5 | ) |   |   | $ | (1.9 | ) |   |
| **Non-qualified  hedges**                                    |       |                                                 | 3.2        |                                                |       |   | (9.6 | ) |   |   | 1.4 |   |   |   | (20.7 | ) |   |
| **Marketing**                                                |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Non-qualified  hedges**                                    |       |                                                 | 21.9       |                                                |       |   | (43.1 | ) |   |   | 53.2 |   |   |   | (37.8 | ) |   |
| **Discontinued  hedges**                                     |       |                                                 | —     |                                                |       |   | — |   |   |   | — |   |   |   | (9.0 | ) |   |
| **Derivative fair value gains (losses)**                     |       |                                                 | $          | 23.7                                                |       |   |   | $ | (52.6 | ) |   |   | $ | 53.1 |   |   |   | $ | (69.4 | ) |   |
|                                                              |            |                                                      |            |                                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

In December 2005, wesettled natural gas collars representing derivative financial instruments onforecasted sales of 2,000 million British thermal units per day, or MMBtu/d, ofnatural gas through 2011. The settlement of these collars reduced the amount ofnon-cash, market-to-market gains reflected above in our Natural Gas segment at September 30,2006.

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**RESULTS OFOPERATIONS—BY SEGMENT**

*Liquids*

Thefollowing tables set forth the operating results and statistics of our Liquidssegment assets for the periods presented:

| ** **                                                | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|-----------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                | ** ** | **   2006   **         | ** ** | **   2005   **        | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                | ** ** | **(unaudited; in millions)**               | ** ** |
| **Operating Results**                                     | ** ** |                                                 | ** ** | ** **                                          |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| **Operating revenues**                                    |       |                                                 | $          | 127.2                                               | ** ** |   |   | $ | 104.1 | ** ** |   | $ | 374.7 | ** ** | $ | 303.1 |   |
| **Operating and administrative**                          |       |                                                 | 36.0       | ** **                                          |       |   | 36.1 | ** ** |   | 99.7 | ** ** | 105.5 |   |
| **Power**                                                 |       |                                                 | 27.8       | ** **                                          |       |   | 19.0 | ** ** |   | 78.3 | ** ** | 53.2 |   |
| **Depreciation and amortization**                         |       |                                                 | 16.0       | ** **                                          |       |   | 18.3 | ** ** |   | 47.8 | ** ** | 53.6 |   |
| **Operating expenses**                                    |       |                                                 | 79.8       | ** **                                          |       |   | 73.4 | ** ** |   | 225.8 | ** ** | 212.3 |   |
| **Operating Income**                                      |       |                                                 | $          | 47.4                                                | ** ** |   |   | $ | 30.7 | ** ** |   | $ | 148.9 | ** ** | $ | 90.8 |   |
| **Operating Statistics**                                  | ** ** |                                                 | ** ** | ** **                                          |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| **Lakehead  system:      ** | ** ** |                                                 | ** ** | ** **                                          |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| **United States**(1)                                      |       |                                                 | 1,175      | ** **                                          |       |   | 1,007 | ** ** |   | 1,174 | ** ** | 1,023 |   |
| **Province of Ontario**(1)                                |       |                                                 | 275        | ** **                                          |       |   | 283 | ** ** |   | 306 | ** ** | 295 |   |
| **Total deliveries**(1)                                   |       |                                                 | 1,450      | ** **                                          |       |   | 1,290 | ** ** |   | 1,480 | ** ** | 1,318 |   |
| **Barrel miles (billions)**                               |       |                                                 | 97         | ** **                                          |       |   | 82 | ** ** |   | 291 | ** ** | 249 |   |
| **Average haul (miles)**                                  |       |                                                 | 725        | ** **                                          |       |   | 691 | ** ** |   | 721 | ** ** | 691 |   |
| **Mid-Continent  system deliveries**(1)                   |       |                                                 | 244        | ** **                                          |       |   | 259 | ** ** |   | 247 | ** ** | 225 |   |
| **North Dakota system  deliveries**(1)                    |       |                                                 | 89         | ** **                                          |       |   | 84 | ** ** |   | 90 | ** ** | 87 |   |
| **Total Liquids Segment  Delivery Volumes**(1)            |       |                                                 | 1,783      | ** **                                          |       |   | 1,633 | ** ** |   | 1,817 | ** ** | 1,630 |   |

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(1)                Average barrelsper day (“Bpd”) in thousands.

***Three months ended September 30, 2006 comparedwith three months ended September 30, 2005***

Our Liquids segment accounted for $47.4 million ofoperating income during the three months ended September 30, 2006, representinga $16.7 million increase over the same period in 2005. The favorable results ofour Liquids segment assets reflect continuing growth in our transportationvolumes while actively managing the costs of our services. The majority of thisincrease relates to significantly improved results on our Lakehead system.

Operating revenuesof our Liquids segment assets increased $23.1 million to $127.2 million for thethird quarter of 2006 compared with $104.1 million earned in the third quarterof 2005. As indicated in the table above, total delivery volumes of our Liquidssegment averaged 1.783 million Bpd in the third quarter of 2006, representing a0.15 million Bpd increase from the 1.633 million Bpd delivered in the thirdquarter of 2005. This accounted for an increase in operating revenues ofapproximately $10.2 million. The increases in deliveries on our Liquidssystems are primarily derived from increased production of Western Canadiancrude oil delivered to our Lakehead system. The increases of deliveries areattributable to the following:

·       Suncor,an oil sands producer in Alberta, Canada, experienced a fire at its upgradersite in January 2005, which affected production for the majority of 2005. Inlate September 2005, Suncor completed repairs and an expansion to itsupgrader site. Suncor’s production levels have increased since that time.

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·       Conventionalheavy crude oil and bitumen production have increased as existing and newfacilities add to capacity. Also, bitumen production was higher during the thirdquarter of 2006, as the nature of the cyclical steaming process used toextract it from the ground can cause production timing differences during theyear.

Contributing to the revenue growth of our Liquidssegment are the increases in the average tariffs on all three of our Liquidssystems which resulted in higher operating revenue during the third quarter of2006 of approximately $10.5 million. These tariff increases were mostly theresult of the annual index rate increase allowed by the Federal EnergyRegulatory Commission (“FERC”) representing the Producers Price Index forFinished Goods plus 1.3 percent (PPIFG + 1.3) effective July 1, 2006, forour base system tariffs. On our Lakehead system, we increased our rates by anaverage of 3.0 percent, which is less than the amount allowed under the index. Onour Lakehead system, new tariffs also went into effect on April 1, 2006for an adjustment on the Terrace expansion program surcharge due to lower thanexpected volumes moving on the Lakehead system, and new facilities in service, thatwere not operating during the third quarter of 2005.

Operating and administrative expenses for the thirdquarter 2006 and 2005 were approximately $36 million. Lower oilmeasurement losses, environmental costs and property taxes, partially offset byhigher workforce related costs were the predominant causes for there being nosignificant changes between periods.

Oil measurementgains and losses occur as part of the normal operating conditions associatedwith our Liquids pipelines. The three types of oil measurement gains and lossesare:

·       physical,which occur through evaporation, shrinkage, differences in measurement betweenreceipt and delivery locations and other operational incidents;

·       degradation,which results in the pipelines from mixing at the interface between higherquality light crude oil and lower quality heavy crude oil; and

·       revaluation,which is a function of crude oil prices, the level of the carrier’s inventoryand the inventory positions of customers.

During the fourth quarter of 2005, we identifiedcertain operating conditions on connected third-party systems that werecontributing to higher levels of physical losses on our Lakehead system.Improvements to oil measurement processes have resulted in lower physicallosses during the third quarter of 2006. We expect these improvements to have acontinuing positive impact on our oil measurement losses throughout the year.We estimate that total oil measurement losses for 2006 will be approximately $5million, compared with $18 million in 2005, assuming crude oil prices remaincomparable to 2005 levels. Power costs increased $8.8 million in the thirdquarter of 2006, compared to the same period in 2005, primarily due toincreased volumes on the Lakehead system and, to a lesser extent, increasedpower rates.

We completed adepreciation study of the Lakehead system in the first quarter of 2006 thatresulted in extending the composite remaining service life of the system assetsfrom 23 to 26 years. The effect of this change was a decrease to depreciationexpense of approximately $2.8 million for the three months ended September 30,2006. We expect the impact of the depreciation study to be a reduction ofdepreciation expense by approximately $11 million for the full year of2006.

***Nine months ended September 30, 2006 comparedwith nine months ended September 30, 2005***

Our Liquids segmentaccounted for $148.9 million of operating income during the nine monthsended September 30, 2006, representing a $58.1 million increase over thesame period in 2005. The components comprising our operating income changed during the first nine months of 2006 comparedwith the first nine months of 2005 primarily for the same reasons as notedabove in the three-month analysis.

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*Future ProspectsUpdate for Liquids*

We and Enbridge Inc. (“Enbridge”)continue to actively work with our customers to develop transportation optionsthat will allow western Canadian crude oil access to new markets.

*Partnership Projects*

In conjuction with Enbridge, we announced in 2005 theapproval of the 400,000 Bpd Southern Access expansion project, which receivedendorsement from the Canadian Association of Petroleum Producers (“CAPP”), atrade association that represents a large majority of the Lakehead system’scustomers. We are undertaking the U.S. portion of the expansion on our Lakeheadsystem with the first stage to add approximately 44,000 Bpd of capacity in 2007and up to an additional 146,000 Bpd by early 2008. The first stage includes anew pipeline between Superior and Delavan, Wisconsin, along with pump stationenhancements upstream and downstream of this segment. The second stage of theexpansion project will provide additional upstream pumping capacity and a newpipeline from Delavan to Flanagan, Illinois, with completion expected in early2009. Completion of the total Southern Access expansion project will create a454-mile pipeline with approximately 400,000 Bpd of incremental capacityon our Lakehead system.

On March 16, 2006, the Federal Energy RegulatoryCommission (“FERC”) approved an Offer of Settlement with respect to tariffprinciples for the Southern Access expansion, which were negotiated with CAPP.In July 2006, we obtained support from shippers and CAPP to increase thediameter of the new pipeline segments of the project from 36 inches, to whichthe previously negotiated tariff principles apply, up to 42 inches. Theincremental capital cost of the larger diameter pipe is currently estimated atapproximately $157 million, bringing our total estimated portion of the costs toapproximately $1.3 billion. The larger diameter will not provide increasedcapacity in the near term but does increase the ultimate capacity of the linefrom 800,000 Bpd to 1,200,000 Bpd with expenditures for additional pumping.This places us in a favorable position to secure future expansion opportunitiesfor our Lakehead system. We will defer any return on the incremental capitaluntil the additional capacity is required by shippers (see discussion of AlbertaClipper project below). In the interim, shippers will absorb all theincremental operating costs of the larger diameter line but will benefit fromreduced power costs at higher throughput levels. Fieldwork has commenced on theproject and pipe has been ordered to ensure full completion in early 2009.

Based on forecasts of oil sands production growthprepared by Enbridge, as well as forcasts by CAPP, we believe that there willbe a need for additional export pipeline capacity out of Western Canada overand above projects which have already received shipper support. Based on thisanalysis, as well as interest expressed by shippers, we and Enbridge areplanning to develop the Alberta Clipper project. This project will involveconstruction of a 36-inch diameter heavy crude line fromHardisty, Alberta to Superior, Wisconsin in conjunction with additionalpumping power applied to the Southern Access 42-inch pipe from Superiorto Flanagan. We anticipate that our share of the cost of this project ascurrently proposed will approximate $750 million, excluding the approximatecost of $157 million to “prebuild” Southern Access to 42 inches as discussedabove.

Alberta Clipper was originally planned to be acontract carrier pipeline based on interest expressed by selected shippers inproviding throughput commitments in return for assured access to capacity.Based on discussions with a broader group of shippers the preference is forAlberta Clipper to be a common carrier line fully integrated with theEnbridge/Lakehead mainline systems for tolling purposes, provided that it canbe developed on a timely basis. Depending on the timing of other exportcapacity projects, Alberta Clipper could be required to be in service between2009 and 2011. To maintain the option to achieve an in-service date in thefourth quarter of 2009, we and Enbridge will seek to reach agreement withshippers on the project terms in time to permit filing of regulatoryapplications before the end of 2006.

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Work is proceeding on our previously announced NorthDakota system expansion. Three critical hydrostatic pressure tests have beensuccessfully completed and the North Dakota Public Service Commission approvalshave been obtained for all phases of the project. Additionally, we have filedthe applicable toll surcharges with the FERC with no objections received. Theexpansion will add approximately 30,000 Bpd of mainline throughput capacity andexpand the system’s feeder segment by approximately 30,000 Bpd at an estimatedcost of $70 million. The expansion is supported by increasing crude oilproduction from the Williston Basin in Montana and North Dakota and is expectedto be completed in the latter half of 2007. We expect our fourth quarter 2006volumes to average approximately 95,000 Bpd due to the recent completion of thehydrotest program and addition of drag reducing agents at pump stations alongthe pipeline.

We continue to experiencestrong interest from customers in securing access to long-term contract storagecapacity at our Cushing, Oklahoma terminal. During the second quarter weobtained commitments and initiated construction activities for a further 1.7million barrels of storage capacity at an expected cost of approximately $35million. This will bring the total capacity of our terminal to approximately16.9 million barrels of which approximately 1.5 million are barrels requiredas operational tankage to support our Mid-Continent liquids pipeline systems, withthe balance available for contract storage.

*Enbridge and Other Projects*

During the first quarter of 2006, Enbridge completedthe reversal of its Spearhead Pipeline that now flows from Chicago, Illinois toCushing, Oklahoma, with a capacity of 125,000 Bpd. In March 2006, thefirst western Canadian crude oil was delivered through this system into themajor oil hub at Cushing. We expect to benefit from the reversal of theSpearhead pipeline as western Canadian crude oil will be carried on ourLakehead system as far as Chicago, and then transferred to the Spearheadpipeline.

In April 2006, ExxonMobil announced it hadcompleted the reversal of two of its crude oil pipelines allowing up to 66,000Bpd of Canadian crude oil to flow from the U.S. Midwest to the U.S. Gulf Coast.The combined reversed pipeline is linked to our Lakehead system at Chicago viathe Mustang Pipe Line Partners system to Patoka, Illinois. The Mustang PipeLine Partners system is 30% owned by an affiliate of Enbridge. ExxonMobil hasreceived firm commitments from Canadian shippers for an average of 50,000 Bpdof capacity on the lines from Patoka, to Nederland, Texas for the next fiveyears. The connection of our Lakehead system with this new market should alsosupport increased throughput on our Lakehead system; however, the reversedExxonMobil system is also capable of transporting western Canadian crude oilmoved via other competing pipelines into the Patoka market.

In July 2006, Enbridge announced that it receivedsupport from shippers and CAPP for its 36-inch diameter Southern AccessExtension pipeline from Flanagan, Illinois to Patoka, Illinois. The extensionwill broaden the reach of the Enbridge/Lakehead mainline system to incrementalmarkets accessible from the Patoka hub. The project will be undertaken byEnbridge; however, it will benefit us through incremental volumes movingthrough our Lakehead system to reach this extension. The Southern AccessExtension will be integrated with our Lakehead system for tolling purposes on adistance-based rolled-in basis, with no toll impact on our Lakehead systemrevenue. 

During the third quarter, Enbridge completed a successfulopen season on its Southern Lights diluent pipeline from Chicago, Illinois toEdmonton, Alberta. The Southern Lights pipeline responds to interest from anumber of western Canadian producers to increase the availability of diluent inAlberta. Diluent is required to transport the heavy oil and bitumen beingproduced in increasing volumes from the Alberta oil sands. The project willrequire approval of the Board of Directors of Enbridge Energy Management,L.L.C. (“Enbridge Management”) for exchange of a 156-mile section ofpipeline we own for a similar section of a new pipeline to be constructed aspart of the project. We expect to benefit from increased heavy crude shipments,which will be facilitated by the diluent line. In addition, this projectinvolves a 

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reconfiguration of thePartnership’s light crude mainline system which will provide an additional30,000 to 50,000 Bpd of effective capacity at no cost to us. Once this capacityis utilized it will generate additional transportation revenue for us. Thisproject is expected to be in service during 2009, coinciding with thecompletion of the Southern Access project.

Shippers have indicatedinterest to Enbridge in development of additional pipeline capacity to transportCanadian crude oil to the U.S. Gulf Coast, including the potential for a directline from Alberta to the Gulf Coast. Enbridge is examining a number ofalternatives to respond to this interest, including alternatives that wouldextend off our Lakehead system, utilizing either existing pipelines which couldbe connected and reversed, or newly constructed extensions. These alternativeswould complement our Lakehead system and support its expansion. Enbridge hasindicated that a direct line would require a minimum of 400,000 Bpd ofthroughput commitments to be economic, and could not be in service before 2011.A direct line, if developed by Enbridge or any other party, would compete withour Lakehead system.

***Natural Gas***

Thefollowing tables set forth the operating results of our Natural Gas segmentassets and approximate average daily volumes of our major systems in MMBtu/dfor the periods presented:

| ** **                          | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|-------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                          | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                          | ** ** | **(unaudited; in millions)**               | ** ** |
| **Operating Results**               |       |                                                 |       |                                                |       |   |   |   |   |
| **Operating revenues**              |       | $                                                    | 686.6      |                                                | $          | 597.9 |   | $ | 2,231.1 |   | $ | 1,544.8 |   |
| **Cost of natural gas**             |       | 568.0                                                |       | 513.9                                               |       | 1,908.4 |   | 1,299.9 |   |
| **Operating and administrative**    |       | 56.9                                                 |       | 44.3                                                |       | 150.6 |   | 126.3 |   |
| **Depreciation and amortization**   |       | 18.7                                                 |       | 18.1                                                |       | 53.2 |   | 49.9 |   |
| **Operating expenses**              |       | 643.6                                                |       | 576.3                                               |       | 2,112.2 |   | 1,476.1 |   |
| **Operating Income**                |       | $                                                    | 43.0       |                                                | $          | 21.6 |   | $ | 118.9 |   | $ | 68.7 |   |
| **Operating  Statistics (MMBtu/d)** | ** ** | ** **                                           | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| **East  Texas**(1)                  |       | 1,062,000                                            |       | 904,000                                             |       | 998,000 |   | 841,000 |   |
| **Anadarko**                        |       | 588,000                                              |       | 489,000                                             |       | 573,000 |   | 473,000 |   |
| **North Texas**                     |       | 302,000                                              |       | 267,000                                             |       | 288,000 |   | 264,000 |   |
| **South  Texas**(1)                 |       | —                                               |       | 31,000                                              |       | — |   | 34,000 |   |
| **UTOS**                            |       | 205,000                                              |       | 154,000                                             |       | 197,000 |   | 181,000 |   |
| **MidLa**                           |       | 144,000                                              |       | 129,000                                             |       | 119,000 |   | 113,000 |   |
| **AlaTenn**                         |       | 32,000                                               |       | 42,000                                              |       | 40,000 |   | 59,000 |   |
| **KPC**                             |       | 19,000                                               |       | 8,000                                               |       | 31,000 |   | 29,000 |   |
| **Bamagas**                         |       | 162,000                                              |       | 110,000                                             |       | 94,000 |   | 44,000 |   |
| **Other major intrastates**         |       | 158,000                                              |       | 164,000                                             |       | 156,000 |   | 197,000 |   |
| **Total**                           |       | 2,672,000                                            |       | 2,298,000                                           |       | 2,496,000 |   | 2,235,000 |   |

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(1)     In December 2005, we sold the South Texas assets and a sourgas system in East Texas which had a combined average daily volume for both thethree and nine months ended September 30, 2005 of approximately 57,000MMBtu/d. 

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***Three months ended September 30, 2006 comparedwith three months ended September 30, 2005***

Our Natural Gas segment produced $43.0 million ofoperating income in the third quarter of 2006, an increase of $21.4 millionfrom $21.6 million of operating income generated in the corresponding period of2005. The increase in operating income is primarily attributable to favorablecommodity prices which contributed to higher revenue generated by ourprocessing assets in excess of the cost we incur for the natural gas used inprocessing. Additionally, operating income was higher due to volume increaseson each of our major systems resulting from additional wellhead supplycontracts and the expansion of our transportation and processing capacity.

Average daily volumes on our major natural gas systemswere up approximately 16% in the third quarter of 2006, compared with thecorresponding period in 2005. We have continued to experience volume growth inthe areas served by our natural gas assets as a result of additional wellheadsupply contracts, predominantly on our East Texas, North Texas and Anadarkosystems. Drilling activity continues to be robust in the Anadarko Basin,Bossier Trend and Barnett Shale areas served by our systems. Also contributingto the increase in volumes is an 80-mile pipeline we acquired in April 2006that is complimentary to our existing East Texas system and providedapproximately 60,000 MMBtu/d of incremental volume. We expect increasingvolumes on our major natural gas systems to result from our continuinginvestments to expand the capacity of our systems.

During the first two months of the third quarter of2006, NGL and crude oil prices remained high relative to natural gas priceswhich have declined from the high prices reached in late 2005. As a result ofthis pricing environment, the revenue generated by our processing assets lessthe cost of natural gas purchased for processing was greater than the amountswe realized in the comparable period of 2005. Late in the third quarter, NGLand Crude oil prices began to decline faster than natural gas prices which mayreduce revenue from our processing assets less the cost of natural gaspurchased for processing during the remainder of 2006. A variable element ofthe Natural Gas segment’s operating income is derived from keep-wholeprocessing of natural gas. Operating income derived from our keep-wholeprocessing for the three months ended September 30, 2006, wasapproximately $16*** ***million, compared withapproximately $9 million for the same period in 2005. 

A portion of our Natural Gas segment is exposed tocommodity price risks associated with percent of proceeds, percent of liquids,or percentage of index contracts that we negotiate with producers. Under theterms of these contracts, we retain a portion of the natural gas and NGLs weprocess in exchange for providing these producers with our services. In orderto protect our unitholders from the volatility in cash flows that can resultfrom fluctuations in commodity prices, we enter into derivative financialinstruments to fix the sales price of the natural gas and NGLs we anticipatereceiving under the terms of these contracts. As a result of entering intothese derivative financial instruments, we have largely fixed the amount ofcash that we will receive in the future when we sell the processed natural gasand NGLs, although the market price of these commodities will continue tofluctuate during that time. Another significant portion of the revenue wereceive is derived from fees charged for gathering and treating of natural gasvolumes and other related services which are not directly dependent oncommodity prices.

Operating income of our Natural Gas segment for thethird quarter of 2006 includes unrealized non-cash, mark-to-market net gains of$1.8 million, including $1.4 million of losses due to hedge ineffectiveness. Inthe third quarter of 2005, our operating income was reduced by $9.5 million ofunrealized, non-cash, market-to-market losses that we incurred, primarily fromderivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133. The non-cash market-to market losses in thethird quarter of 2005 were partially due to natural gas supply disruptionscaused by hurricanes Rita and Katrina that caused an increase in natural gasprices. The non-cash mark-to-market net gains in 2006 are primarily derivedfrom our derivative financial instruments that do not qualify for hedgeaccounting treatment under SFAS No. 133. We expect the net mark-to-marketgains and losses 

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to be offset when therelated physical transactions are settled (refer also to the discussionsincluded in Note 10 of Item 1. Financial Statements, above and below underDerivative Activities, and Item 3. Quantitative and Qualitative DisclosuresAbout Market Risk).

The positive growth in our natural gas and NGLgathering, processing and transportation volumes for the third quarter of 2006was partially offset by increases in operating costs that are mostly related tovolume growth and somewhat variable with volumes. The increase in operating andadministrative costs is attributable to the continuing growth and expansion ofour natural gas systems. As a result of the increase in volumes and thephysical growth of our major systems, we have experienced an increase inworkforce related costs associated with the operation of these assets.Workforce related costs in addition to the cost of material and supplies haveincreased as a result of the expansion projects we are constructing to extendthe service capability of our existing systems. Additionally, repair andmaintenance costs were higher due to pipeline integrity work and compressormaintenance performed during the quarter.

We expect workforcerelated costs in addition to the cost of materials and supplies to continueincreasing as a result of the large number of pipeline expansions beingperformed in our industry that are causing competitive constraints across theUnited States. Our ability to attract and retain the resources necessary tocomplete our expansion projects may be affected by these constraints in thefuture causing additional increases in workforce related cost. In addition, ourability to obtain materials and supplies at competitive rates given the highdemand in our industry for such materials as pipe and compression may alsoincrease operating and capital costs in the future. 

***Nine months ended September 30, 2006 comparedwith nine months ended September 30, 2005***

Our Natural Gas segment produced $118.9 million ofoperating income in the first nine months of 2006, an increase of $50.2 millionfrom the $68.7 million of operating income generated in the correspondingperiod of 2005.

Average daily volumes on our major natural gas systemsincreased 12%, or approximately 261,000 MMBtu/d, for the nine months ended September 30,2006, compared with the corresponding period in 2005. The increase in volumesis consistent with the reasons cited above in our three-month analysis.

As previously noted under our three-month analysis, aportion of our Natural Gas segment’s operating income is derived fromprocessing natural gas under keep-whole arrangements. Operating income derivedfrom keep-whole processing on our major systems increased toapproximately $44 million for the nine months ended September 30, 2006,compared with approximately $19 million for the corresponding period in2005 for the same reasons discussed above in our three-month analysis.

Operating income of our Natural Gas segment for thenine months ended September 30, 2006 includes non-cash, mark-to-market netlosses of $0.1 million, including $1.5 million of losses due to hedgeineffectiveness. In the nine months ended September 30, 2005, ouroperating income was reduced by the $22.6 million of non-cash, mark-to-marketlosses that we incurred for derivative financial instruments that do notqualify for hedge accounting treatment under SFAS No. 133 and $1.9 millionof losses due to hedge ineffectiveness. The non-cash mark-to-market net lossesin 2006 are primarily derived from hedge ineffectiveness partially offset bygains from our derivative financial instruments that do not qualify for hedgeaccounting treatment under SFAS No. 133 as discussed above under ourthree-month analysis (refer also to the discussions included in Note 10 of Item1. Financial Statements, below under Derivative Activities, and Item 3.Quantitative and Qualitative Disclosures About Market Risk).

Operating andadministrative costs associated with our Natural Gas segment were$24.3 million greater for the nine months ended September 30, 2006,than for the corresponding period in 2005. The increase in operating andadministrative costs of our Natural Gas segment increased for the same reasonsdiscussed above in our three-month analysis.

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***FutureProspects Update for Natural Gas***

We continue to assess various acquisition andexpansion opportunities to pursue our strategy for growth. The market foracquiring energy transportation assets continues to remain active andsignificant competition among prospective acquirers of assets persists. Whilewe remain committed to making accretive acquisitions in or near areas where wealready operate or have a competitive advantage, we will continue to focus ourefforts primarily on development of our existing pipeline systems. Although oneof our objectives is to grow our natural gas business through acquisitions, wemay and have pursued opportunities to divest any non-strategic natural gasassets as conditions warrant.

Results of our natural gas gathering and processingbusiness depend upon the drilling activities of natural gas producers in theareas we serve. During the first nine months of 2006, increased drilling in theareas where our gathering systems are located has continued to contribute toour volume growth. We expect the growth trend in these areas to continue asindicated by an external production forecast and the robust drilling indicatedby rig counts in the areas served by our systems.

In the first ninemonths of 2006, we have completed the following projects:

·       Theexpansion of our existing Zybach processing facility to a capacity of 150million cubic feet per day, or MMcf/d, of natural gas from the initial capacityof approximately 105 MMcf/d when we placed the plant in service in April 2005.

·       Thelink between our North Texas and East Texas systems became fully operationalduring the third quarter of 2006. As expected, the completion of thisconnection has increased the utilization of our 500 MMcf/d intrastate pipelinethat we placed in service in June 2005 on our East Texas system byproviding additional market access to customers of our North Texas system.

·       Theconstruction of our 120 MMcf/d Henderson natural gas processing facility on ourEast Texas system was completed at the end of the third quarter of 2006. In thefourth quarter of 2006, we expect the addition of this processing facility tobegin contributing to the favorable return we are experiencing on ourprocessing assets.

In the East Texasregion, we initiated construction on several projects during 2006 to increaseour gathering and treating infrastructure and market access capability. Theseprojects continue to progress according to schedule and include:

·       A36-inch diameter intrastate pipeline from Bethel, Texas to Orange County,Texas with capacity of approximately 700 MMcf/d, to be completed in stagesthroughout 2007. The new pipeline will provide service to a number of majorindustrial and power companies in Southeast Texas and will cross a number ofinterstate pipelines. We currently anticipate the expansion project will costapproximately $610 million.

·       A 200 MMcf/d treatingfacility to be built near Marquez, Texas will be connected to the 36-inchdiameter intrastate pipeline via a new 24-inch diameter pipeline, to becompleted in early 2007.

·       A number of upstreamfacilities, including gathering pipelines to tie existing facilities into thenew intrastate pipeline, will also be completed in early 2007.

On our North Texas system, we commenced constructionof a new 35 MMcf/d gas processing plant and related upstream facilities toaccommodate anticipated growth in the region. These facilities are expected tobecome operational in the first half of 2007. 

The rate of growth on our Anadarko system continues toexceed projections as a result of the rapid development of the Granite Washplay in Hemphill and Wheeler counties. To accommodate this continuing volumegrowth, the Anadarko system requires additional processing capacity and fieldcompression. We are continuing to make progress in increasing processingcapacity and field compression 

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in the region from 230MMcf/d at December 31, 2005 to approximately 440 MMcf/d to accommodate thevolume growth. We have added approximately 50 MMcf/d of processing capacityduring 2006 and expect to place the additional processing capacity and fieldcompression in service in early 2007.

When fully operational in late 2007, the new assets weare constructing will provide an additional source of stable cash flow for us. We continue to evaluate other projects that couldfurther integrate our major Texas-centered pipeline systems.

In December 2005,Calpine Corporation (“Calpine”) and many of its subsidiaries, including thesubsidiary that owns the two utility plants served by our Bamagas system, filedvoluntarily petitions to restructure under Chapter 11 of the United StatesBankruptcy Code. In April 2006, Calpine announced its intent to sellapproximately 20 of its non-core and non-strategic power plants, although theplants to be sold have not been announced. Calpine has continued to performunder the terms of its agreement with Bamagas and we remain confident that anylosses we may incur with respect to Calpine’s bankruptcy will be minimal. Wecontinue to monitor the Calpine bankruptcy proceedings and will recognize anylosses that may result when it becomes evident that a loss has been incurred. 

***Marketing***

Thefollowing table sets forth the operating results for the Marketing segmentassets for the periods presented:

| ** **                        | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|-----------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                        | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                        | ** ** | **(unaudited; in millions)**               | ** ** |
| **Operating revenues**            |       | $                                                    | 718.5      |                                                | $          | 1,107.6 |   | $ | 2,239.8 |   | $ | 2,544.5 |   |
| **Cost of natural gas**           |       | 697.9                                                |       | 1,145.9                                             |       | 2,190.8 |   | 2,582.5 |   |
| **Operating and administrative**  |       | 1.1                                                  |       | 1.4                                                 |       | 3.7 |   | 3.1 |   |
| **Depreciation and amortization** |       | 0.1                                                  |       | 0.1                                                 |       | 0.3 |   | 0.4 |   |
| **Operating Expenses**            |       | 699.1                                                |       | 1,147.4                                             |       | 2,194.8 |   | 2,586.0 |   |
| **Operating Income (loss)**       |       | $                                                    | 19.4       |                                                | $          | (39.8 | ) | $ | 45.0 |   | $ | (41.5 | ) |

 

***Three months ended September 30, 2006 comparedwith three months ended September 30, 2005***

A majority of the operating income of our Marketingsegment is derived from selling natural gas received from producers on ourNatural Gas segment pipeline assets to customers who need natural gas. Amajority of the natural gas we purchase is produced in Texas markets where wehave limited physical access to the primary interstate pipeline deliverypoints, or hubs such as Waha, Texas and the Houston Ship Channel. As a result,our Marketing business must use third-party pipelines to transport the naturalgas to these markets where it can be sold to our customers. However, physicalpipeline constraints often require our Marketing business to transport naturalgas to alternate market points. Under these circumstances, our Marketingsegment will sell the purchased gas at a pricing index that is different fromthe pricing index at which the gas was purchased. This creates a price exposurethat arises from the relative difference in natural gas prices between thecontracted index at which the natural gas is purchased and the index underwhich it is sold, otherwise known as the “spread.” The spread can varysignificantly due to local supply and demand factors. Wherever possible, thispricing exposure is economically hedged using derivative financial instruments.However, the structure of these economic hedges often precludes our use ofhedge accounting under the requirements of SFAS No. 133, which can createvolatility in the operating results of our Marketing segment.

To ensure that we have access to primary pipelinedelivery points, we often enter into firm transportation agreements oninterstate and intrastate pipelines. To offset the demand charges associated 

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with these firmtransportation contracts, we look for market conditions that allow us to lockin the price differential or spread between the pipeline receipt point andpipeline delivery point. This allows our Marketing business to lock in a fixedsales margin inclusive of pipeline demand charges. We accomplish this bytransacting basis swaps between the index where the natural gas is purchasedand the index where the natural gas is sold. By transacting a basis swapbetween those two indices, we can effectively lock in a margin on the combinednatural gas purchase and the natural gas sale, mitigating the demand charges onfirm transportation agreements and limiting the Partnership’s exposure to cashflow volatility that could arise in markets where the firm transportationbecomes uneconomic. However, the structure of these transactions precludes ouruse of hedge accounting under the requirements of SFAS No. 133, which cancreate volatility in the operating results of our Marketing segment.

In addition to natural gas basis swaps, we contractfor storage to assist with balancing natural gas supply and end use marketsales. In order to mitigate the absolute price differential between the cost ofinjected natural gas and withdrawn natural gas, as well as storage fees, theinjection and withdrawal price differential, or “spread,” is hedged by buyingfixed price swaps for the forecasted injection periods and selling fixed priceswaps for the forecasted withdrawal periods. When the injection and withdrawalspread increases or decreases in value as a result of market price movements,we can earn additional profit through the optimization of those hedges in boththe forward and daily markets. Although each of these hedge strategies aresound economic hedging techniques, these types of financial transactions do notqualify for hedge accounting under the SFAS No. 133 guidelines. As such, thenon-qualified hedges are accounted for on a mark-to-marketbasis, and the periodic change in their market value, although non-cash, willimpact the income statement.

In the third quarter of 2006, the operating income ofour Marketing segment increased $59.2 million to $19.4 million, from aloss of $39.8 million for the corresponding period in 2005. Included inoperating income for the third quarter of 2006 are unrealized, non-cash,mark-to-market gains of approximately $21.9 million compared with unrealizedmark-to-market losses of $43.1 million for the comparable period in 2005,associated with derivative financial instruments that do not qualify for hedgeaccounting treatment under SFAS No. 133. The unrealized, mark-to-marketgains for the three months ended September 30, 2006, are the result of adecline in the forward and daily market price of natural gas from thehistorically high prices experienced at September 30, 2005. We expectthese net mark-to-market gains to be offset when the related physicaltransactions are settled (refer also to the discussion included below underDerivative Activities, Note 10 of Item 1. Financial Statements, andItem 3. Quantitative and Qualitative Disclosures About Market Risk). 

The operating results ofour Marketing business for the three months ended September 30, 2006,include a non-cash charge of $6.6 million to adjust the cost basis of ournatural gas inventory to fair market value at September 30, 2006. Naturalgas prices as published by Gas Daily for Henry Hub were approximately $6.09 perMMBtu at June 30, 2006, which had declined to $4.18 per MMBtu at September 30,2006. As a result of this near-term decline in the price of natural gas at ourstorage locations from June 30, 2006 to September 30, 2006, theweighted average cost of our natural gas inventory at September 30, 2006,exceeded the market price of natural gas by approximately $6.6 million. As aresult of this decline, we reduced the cost basis of our inventory to fairmarket value at September 30, 2006, by recording a non-cash charge for$6.6 million. Partially offsetting this charge are gains of approximately $2million that we realized upon settlement ofderivative financial instruments hedging our natural gas inventory. Dueto our hedging structures, we expect that a majority of this charge will beoffset by future financial and physical transactions that will settle at thetime the natural gas inventory is sold.

***Nine months ended September 30, 2006 comparedwith nine months ended September 30, 2005***

In the first nine monthsof 2006, the operating income of our Marketing segment increased $86.5 millionto $45.0 million, from a loss of $41.5 million for the correspondingperiod in 2005. Included in 

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operatingincome for the first nine months of 2006 are unrealized, non-cash,mark-to-market net gains of approximately $53.2 million associated withderivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133, as compared with unrealized mark-to-marketnet losses of $46.8 million for the comparable period in 2005. In the thirdquarter of 2005, we recognized approximately $9.0 million of losses for thediscontinuance of hedge accounting for derivative financial instrumentsassociated with forecasted transactions that we determined were not probable ofoccurring (refer also to the discussion included below under DerivativeActivities, Note 10 of Item 1. Financial Statements, and Item 3.Quantitative and Qualitative Disclosures About Market Risk). Thesemark-to-market gains are primarily driven by the decline in natural gas pricessince December 31, 2005, as discussed above in our three-month analysis.

The operating results ofour Marketing business for the nine months ended September 30, 2006,include a non-cash loss of $16.3 million attributable to reducing the costbasis of our natural gas inventory to fair market value. Natural gas prices aspublished by Gas Daily for Henry Hub were approximately $10.08 per MMBtu at December 31,2005, which had declined to $4.18 per MMBtu at September 30, 2006. As aresult of the decline in the price of natural gas from December 31, 2005to September 30, 2006, we recorded charges totaling $16.3 million duringthe nine months ended September 30, 2006 to reduce the cost basis of our inventoryto fair market value. Partially offsetting this charge are gains ofapproximately $3 million that we realized uponsettlement of derivative financial instruments hedging our natural gasinventory. Due to our hedging structures, we expect that a majority ofthese charges will be offset by future financial and physical transactions thatwill settle at the time the natural gas inventory is sold.

***Corporate***

Interest expense was $28.5million and $84.0 million for the three and nine months ended September 30,2006, respectively, compared with $28.4 million and $79.6 million,respectively, for the corresponding periods in 2005. The increase is the resultof higher debt balances and weighted average interest rates, partially offsetby approximately $2.3 million and $5.7 million of interest capitalized on ourconstruction projects for the three and nine months ended September 30,2006, respectively, compared to $0.2 million and $3.4 million, respectively,for the corresponding periods in 2005. Our weighted average interest rate wasapproximately 5.86% for the three and nine months ended September 30,2006, compared with approximately 5.68% and 5.80%, respectively, during thecorresponding periods in 2005.

Included in other incomefor the nine months ended September 30, 2006, is $4.5 million that wereceived as settlement for an insurance claim that we filed in connection withan interruption to the operations of our Lakehead system resulting from a firethat occurred at Suncor’s upgrader site in January 2005.

The Partnership is not ataxable entity for U.S. federal income tax purposes and historically has notbeen a taxable entity for state income tax purposes. Federal and state incometaxes on partnership taxable income were both borne directly by the unitholderswith no entity level tax on the Partnership. In May 2006, the State ofTexas enacted substantial changes to its tax structure beginning in 2007 byimposing a new tax based upon modified gross revenue referred to as the “MarginTax.” We determined the “Margin Tax” to be an income tax as defined underStatement of Financial Accounting Standards No. 109, *Accountingfor Income Taxes*(“SFAS No. 109”). Our initial accounting forthe enactment of this income tax did not materially affect our results ofoperation, financial condition or cash flows.

**LIQUIDITY AND CAPITAL RESOURCES**

***General***

We believe that ourability to generate cash flow, in addition to our access to capital markets, issufficient to meet the demands of our current and future operating growth and investmentneeds. Our primary cash requirements consist of normal operating expenses,maintenance and expansion capital 

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expenditures,debt service payments, distributions to partners, acquisitions of new assets orbusinesses, and payments associated with our derivative transactions. Short-termcash requirements, such as operating expenses, maintenance capital expendituresand quarterly distributions to partners, are expected to be funded from ouroperating cash flows. Margin requirements associated with our derivativetransactions are generally supported by letters of credit issued under ourCredit Facility. We expect to fund long-term cash requirements forexpansion projects and acquisitions from several sources, including cash flowsfrom operating activities, borrowings under our commercial paper program, ourCredit Facility, and the issuance of additional equity and debt securities. Ourability to complete future debt and equity offerings and the timing of any suchofferings will depend on various factors, including prevailing marketconditions, interest rates, our financial condition and credit rating at thetime.

In 2005, we shifted ourbusiness strategy to an emphasis on developing and expanding our existingLiquids and Natural Gas businesses with less focus on acquisitions. Theinternal growth projects we have planned for our Natural Gas business (seeNatural Gas segment—Future Prospects), coupled with the Southern Accessexpansion and other related projects associated with our Lakehead system (seeLiquids segment—Future Prospects), will require significant expenditures ofcapital over the next several years. We expect to permanently fund theseexpenditures from a balanced combination of additional issuances of partnershipcapital and long-term debt. Our planned internal growth projects will requireus to bear the cost of constructing these new assets before we will begin torealize a return on them. While these major projects are under construction,our ability to increase distributions is likely to be limited.

***Capital Resources***

*Available Credit*

A significant source of our liquidity is provided bythe commercial paper market. We have a $600 million commercial paperprogram supported by our long-term Credit Facility, which we access primarilyto provide temporary financing for our operating activities, capitalexpenditures and acquisitions, at rates that are generally lower than the ratesavailable under our Credit Facility. Under the terms of our commercial paperprogram, we may issue up to $600 million of commercial paper. However, theamount of commercial paper we may issue is reduced by any balance ofoutstanding letters of credit in excess of $400 million. At September 30,2006, we had $475 million in principal amount of commercial paper outstandingand could issue an additional $125 million in principal amount of commercialpaper. We expect to extend the capacity of our commercial paper program toapproximately $800 million, which extension will be subject to receipt ofsatisfactory credit ratings from the major credit rating agencies. 

Our Credit Facility alsoprovides us with another significant source of liquidity. In March 2006,we obtained an increase from $800 million to $1 billion in the aggregatecommitment available to us under the terms of our Credit Facility. The amountswe may borrow under the terms of our Credit Facility are reduced by theprincipal amount of our commercial paper issuances and the balance of ourletters of credit outstanding. At September 30, 2006 we had no amountsoutstanding under our Credit Facility and letters of credit totaling$59.1 million. At September 30, 2006, we could borrow$465.9 million under the terms of our Credit Facility after reducing the$1 billion commitment amount by outstanding letters of credit and the principalbalance of commercial paper we have outstanding. We expect to extend thecapacity of our Credit Facility to approximately $1.5 billion in the near term,subject to approval of the lenders that are party to our Credit Facility. Subjectto the expansion of our Credit Facility, we will consider further extending thecapacity of our commercial paper program to $1 billion.

*Unit Issuance*

In August 2006, wereceived net proceeds of approximately $510 million from the issuance of our Class Cunits, including approximately $10 million contributed by our general partnerto maintain its two 

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percentgeneral partner interest. Proceeds from the issuance were partially used toreduce borrowings outstanding under our commercial paper program and to fundour capital expansion projects. We invested the remaining amount in short-termcommercial paper for use in future periods to further reduce our commercialpaper borrowings or fund additional expenditures under our capital expansionprojects. 

***Cash Requirements for Future Growth***

*Capital Spending*

We rely upon cash flow from our operating activitiesand access to the capital markets to provide the funds necessary to execute ourgrowth strategy and complete our projects. Our success with generating andraising capital is a critical factor that determines how much we spend inconnection with our growth objectives. We believe our ability to generate orotherwise access the necessary capital resources is sufficient to meet thedemands of our current and future operating growth needs. Although we currentlyintend to make the forecasted expenditures discussed below, we may adjust thetiming and amounts of projected expenditures as necessary to adapt to changesin economic conditions.

We estimate our capital expenditures based on our longrange strategic operating and growth plans. These estimates may change due tofactors beyond our control, including changes in supplier prices, resourceconstraints and poor economic conditions. Additionally, estimates may change asa result of decisions made at a later date, which may include acquisitions,scope changes or operational considerations.

We categorize our capital expenditures as either coremaintenance or enhancement expenditures. Core maintenance expenditures arethose expenditures that are necessary to maintain the service capability of ourexisting assets and include the replacement of system components and equipmentwhich is worn, obsolete or completing its useful life. Enhancement expendituresimprove the service capability of our existing assets, extend asset usefullives, increase capacities from existing levels, reduce costs or enhancerevenues, and enable us to respond to governmental regulations and developingindustry standards. We made capital expenditures of approximately$514.3 million, including $34.0 million on core maintenanceactivities, during the nine months ended September 30, 2006.

Forthe full year of 2006, we anticipate our capital expenditures to approximatethe following (in millions):

| **System enhancements**         |   | $   | 400    |   |
|---------------------------------|--------|-----|--------|--------|
| **Core maintenance activities** |   | 50  |   |
| **Southern Access expansion**   |   | 165 |   |
| **East Texas expansion**        |   | 350 |   |
| ** **                      |   | $   | 965    |   |

 

We continue to expect our ongoing capital expendituresto be significant over the next three years due to the East Texas expansion andSouthern Access expansion projects. Our outlays for capital expenditures mayincrease as a result of the number of pipeline expansion projects beingconducted in the United States and the resulting demand these projects createfor skilled labor and supply resources. Our ability to attract the resourcesnecessary to complete our expansion projects may be negatively affected by theheavy demand for these resources.

We anticipate funding our system enhancement capitalexpenditures temporarily through the issuance of commercial paper and borrowingunder the terms of our Credit Facility, with permanent debt and equity fundingbeing obtained when appropriate. Core maintenance expenditures are expected tobe funded by operating cash flows.

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Our Southern Access and East Texas expansion projectshave strong support from our customers, and upon completion each project isexpected to have stable cash flows. Although, we have received indications thatthese projects can be readily financed, we intend to structure the capacity ofour Credit Facility to support temporary expansion of our commercial paperprogram which will be refinanced with permanent capital at key milestone datesfor each project.

As of September 30, 2006, we have contractualcommitments totaling $402.9 million for materials and services related to ourorganic growth projects. We anticipate settling these commitments during theremainder of 2006; however, we expect to make additional commitments as ourcapital projects continue to progress.

We also expect to incurcontinuing annual capital and operating expenditures for pipeline integritymeasures to ensure both regulatory compliance and to maintain the overallintegrity of our pipeline systems. Expenditure levels have continued toincrease as pipelines age and require higher levels of inspection ormaintenance; however, these are consistent with industry trends.

*Acquisitions*

We continue to assess various acquisition andexpansion opportunities to grow our business. However, the market for acquiringenergy transportation assets remains competitive. While we remain committed tomaking accretive acquisitions in or near areas where we already operate or havea competitive advantage, we will focus our efforts on development of ourexisting pipeline systems. Additionally, we may pursue opportunities to divestany non-strategic assets as conditions warrant.

We expect that the fundsneeded to achieve growth through acquisitions will be obtained throughissuances of commercial paper, term debt and additional partnership interests.

***Derivative Activities***

We use derivative financial instruments (i.e.,futures, forwards, swaps, options and other financial instruments with similarcharacteristics) to mitigate the volatility of our cash flows and manage therisks associated with market fluctuations in commodity prices. Based on ourrisk management policies, all of our derivative financial instruments areemployed in connection with an underlying asset, liability or anticipatedtransaction and are not entered into with the objective of speculating oncommodity prices.

The following tableprovides summarized information about the timing and expected settlementamounts of our outstanding commodity derivative financial instruments at September 30,2006 for each of the indicated calendar years: 

| ** **             | ** ** | **Notional**                  | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** |
|------------------------|------------|-------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **             | ** ** | **($ in millions)** | ** ** |
| **Swaps**              |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| **Natural gas**(1)     |       | 343,052,395                   |       | $        | (10.7      | )        | $          | (37.9    | )          | $        | (34.9      | )        | $          | (28.3    | )          | $        | (23.9      | ) | $ | (21.5 | ) | $ | (4.7 | ) |
| **NGL**(2)             |       | 8,961,934                     |       | (4.6     | )          | (9.5     | )          | (5.4     | )          | (0.1     | )          | (0.9     | )          | —   |       | —   |       |
| **Crude**(2)           |       | 1,261,164                     |       | (2.0     | )          | (9.7     | )          | (7.3     | )          | (2.0     | )          | (0.5     | )          | (0.1     | )          | —   |       |
| **Options—calls** |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| **Natural gas**(1)     |       | 1,918,000                     |       | (0.1     | )          | (1.2     | )          | (1.2     | )          | (1.2     | )          | (1.1     | )          | (1.0     | )          | —   |       |
| **Options—puts**  |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| **Natural gas**(1)     |       | 1,887,000                     |       | —   |       | —   |       | —   |       | —   |       | 0.1      |       | 0.1      |       | —   |       |
| **Totals**             |       |                          |       | $        | (17.4      | )        | $          | (58.3    | )          | $        | (48.8      | )        | $          | (31.6    | )          | $        | (26.3      | ) | $ | (22.5 | ) | $ | (4.7 | ) |

----

(1)                Notionalamounts for natural gas are recorded in MMBtu.

(2)                Notionalamounts for NGL and Crude are recorded in Bbl.

33

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***Operating Activities***

Net cash provided by ouroperating activities for the nine months ended September 30, 2006 was$229.9 million, an increase of $21.7 million over the $208.2 millionwe generated for the same period in 2005. The improved operating cash flow isprimarily attributable to income contributions from our natural gas processingassets and increased deliveries on our Lakehead system, partially offset bygeneral timing differences in the collection on and payment of our current andrelated party accounts.

***Investing Activities***

We used $87.5 million morein our investing activities during the nine months ended September 30,2006 compared with the same period in 2005. The decrease in expenditures foracquisitions was more than offset by the $252.4 million increase in ourinvestments in property, plant and equipment during the first nine months of2006 over the amount spent during the same period of 2005. The increase in ourcapital expenditures in the first nine months of 2006 is directly attributableto our previously announced expansion projects and a result of our shift instrategy to more internal growth projects.

***Financing Activities***

Net cash provided by our financing activities duringthe nine months ended September 30, 2006 was $463.7 million, comparedwith $249.2 million for the corresponding period in 2005. The increase inour cash flows from financing activities is primarily due to proceeds receivedfrom the issuance of our Class C units in August 2006. We raisedapproximately $510 million from the issuance of our Class C units duringthe first nine months of 2006, which we used to reduce the balance outstandingunder our commercial paper program and to fund our capital expansion projects.

In the first nine months of 2005 we raised $127.5million from the issuance of our Class A units. During the first ninemonths of 2006 we had net commercial paper issuances of $143.9 million, whichinclude gross issuances of $2,488.2 million and gross repayments of $2,344.3million. Additionally, at September 30, 2006 we had gross borrowings and grossrepayments of $90 million on our Credit Facility and had repaid $20 million inprincipal amount of an affiliate loan. During the first nine months of 2005, werepaid $175 million, net of borrowings, under the terms of our Credit Facility, including borrowings and repayments of $565million representing net non-cash settlements with the parties to our CreditFacility.

Distributions to ourpartners were higher in the first nine months of 2006 due to an increase in theweighted average number of units outstanding in relation to the first ninemonths of 2005 and the related increase in the general partner incentivedistributions resulting from the larger number of units outstanding.

**OFF-BALANCESHEET ARRANGEMENTS**

We do not have any off-balancesheet arrangements.

**SUBSEQUENT EVENTS**

***Distribution to Partners***

On October 27, 2006,the Board of Directors of Enbridge Management declared a distribution payableto our partners on November 14, 2006. The distribution will be paid tounitholders of record as of November 6, 2006, of our available cash of$79.6 million at September 30, 2006, or $0.925 per limited partnerunit. Of this distribution, $57.6 million will be paid in cash,$11.5 million will be distributed in i-units to our i-unitholder,$10.1 million will be distributed in Class C units to the holders of ourClass C units and $0.4 million will be retained from the GeneralPartner in respect to the i-unit and Class C unit distributions.

34

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**REGULATORY MATTERS**

***FERC Transportation Tariffs-***Liquids

Beginning July 1, 2006, we increased our ratesfor transportation on our Lakehead, North Dakota and Ozark systems incompliance with the indexed rate ceilings allowed by the FERC. In March 2006,the FERC established a new oil pipeline pricing index for a five-year periodending July 2011. The index is used to establish rate ceiling levels foroil pipeline rate changes. The FERC determined that the Producer Price Indexfor Finished Goods plus 1.3 percent (PPIFG+1.3 percent) should be the oilpricing index for the five year period beginning July 1, 2006. For ourLakehead system indexing only applies to our base rates and not the SEP II,Terrace and Facilities surcharges. Beginning July 1, 2006, we increasedour rates for transportation on our Lakehead system by an average of 3.0percent, which is less than the amount allowed under the index. As an example,on our Lakehead system, the new rate for heavy crude movements from theInternational Boarder near Neche, North Dakota to Chicago, Illinois is $0.919per barrel, which reflects an approximate $0.021 per barrel increase over ratesfiled effective April 1, 2006. In addition to the rates on our Lakeheadsystem, we increased the transportation rates by an average of approximately6.1 percent on our North Dakota and Ozark systems.

Effective April 1,2006, we filed our annual tariff with the FERC for our Lakehead System SEP IIexpansion. This tariff reflected the annual calculation of the SEP II andother surcharges based on true-ups of prior year amounts and estimates for2006, and an adjustment for the Terrace surcharge as a result of lower thanexpected volumes moving on the Lakehead system in 2005. This filing increasedthe tariff for heavy crude oil movements from the Canadian border to Chicago,Illinois, by approximately $0.008 per barrel, to approximately $0.898 perbarrel.

**RECENT ACCOUNTINGPRONOUNCEMENTS NOT YET ADOPTED**

In September 2006,the Financial Accounting Standards Board (FASB) issued FASB Statement No. 157,*Fair Value Measurements.*This statementdefines fair value, establishes a framework for measuring fair value ingenerally accepted accounting principles (GAAP), and expands disclosures aboutfair value measurement. The statement is effective for fiscal years beginningafter November 15, 2007, and with limited exceptions is to be appliedprospectively as of the beginning of the fiscal year initially adopted. We donot expect our adoption of this pronouncement to materially effect ourfinancial statements. However, adoption of this pronouncement may affect ourdisclosures regarding derivative financial instruments and indebtedness.

**Item 3.**                        Quantitativeand Qualitative Disclosures About Market Risk

This information updates, and you should read it in conjunctionwith, our quantitative and qualitative disclosures about market risks reportedin our Annual Report on Form 10-K for the year ended December 31,2005, in addition to information presented in Items 1 and 2 of this QuarterlyReport on Form 10-Q.

Our net income and cash flows are subject tovolatility stemming from changes in commodity prices of natural gas, naturalgas liquids (“NGL” or “NGLs”), condensate and fractionation margins (therelative price differential between NGL sales and the offsetting natural gaspurchases). This market price exposure exists within our Natural Gas andMarketing segments. To mitigate the volatility of our cash flows, we usederivative financial instruments (i.e., futures, forwards, swaps, options andother financial instruments with similar characteristics) to manage the risksassociated with market fluctuations in commodity prices. Based on our riskmanagement policies, all of our derivative financial instruments are employedin connection with an underlying asset, liability and/or forecasted transactionand are not entered into with the objective of speculating on commodity prices.

35

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Thefollowing tables provide information about our derivative financial instrumentsat September 30, 2006 and December 31, 2005, with respect to ourcommodity price risk management activities for natural gas and NGLs, includingcrude oil:

|                                  | ** **   | **At September 30, 2006** | ** **   | **At December 31, 2005** | ** ** |
|----------------------------------|--------------|------------------------------------------|--------------|-----------------------------------------|------------|
| ** **                       | ** **   | ** **                               | ** **   | ** **                              | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                       | ** **   | **Commodity**                            | ** **   | **Notional**(1)                         | ** ** | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **     Asset     ** | ** ** | **     Liability     ** | ** ** |
| ***Contracts maturing in 2006*** | *** *** |                                     | *** *** | *** ***                            |       |   | *** *** | *** *** |   |   | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                          | * *     |                                     | * *     | *** ***                            |       |   | * * | *** *** |   |   | * * | *** *** |   | * * | * * |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed       |         |                                     | Natural gas  | *** ***                            |       |   | 31,746,904 | *** *** |   |   | $ | 5.08 | *** *** |   | $ | 7.39 |   |   | $ | 1.3 | *** *** |   |   | $ | (74.1 | ) |   |   | $ | 380.6 | *** *** |   |   | $ | (11.7 | ) |   |
|                                  |         |                                     | NGL          | *** ***                            |       |   | 25,116 | *** *** |   |   | 39.20 | *** *** |   | 46.29 |   |   | — | *** *** |   |   | (0.2 | ) |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay  variable      |         |                                     | Natural gas  | *** ***                            |       |   | 31,476,769 | *** *** |   |   | 7.30 | *** *** |   | 5.28 |   |   | 68.7 | *** *** |   |   | (5.4 | ) |   |   | 14.5 | *** *** |   |   | (467.8 | ) |   |
|                             |         |                                     | NGL          | *** ***                            |       |   | 1,208,880 | *** *** |   |   | 36.13 | *** *** |   | 39.79 |   |   | 1.6 | *** *** |   |   | (6.0 | ) |   |   | — | *** *** |   |   | (29.7 | ) |   |
|                             |         |                                     | Crude oil    | *** ***                            |       |   | 101,660 | *** *** |   |   | 44.18 | *** *** |   | 64.36 |   |   | — | *** *** |   |   | (2.0 | ) |   |   | 0.2 | *** *** |   |   | (7.8 | ) |   |
| Receive variable/pay variable    |         |                                     | Natural gas  | *** ***                            |       |   | 12,763,662 | *** *** |   |   | 4.18 | *** *** |   | 4.27 |   |   | 0.8 | *** *** |   |   | (2.0 | ) |   |   | 5.2 | *** *** |   |   | (5.2 | ) |   |
| *Options*                        | * *     |                                     | * *     | *** ***                            |       |   | * * | *** *** |   |   | * * | *** *** |   | * * | * * |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                  |         |                                     | Natural gas  | *** ***                            |       |   | 92,000 | *** *** |   |   | 5.79 | *** *** |   | 4.31 |   |   | — | *** *** |   |   | (0.1 | ) |   |   | — | *** *** |   |   | (2.0 | ) |   |
| Puts                             |         |                                     | Natural gas  | *** ***                            |       |   | 61,000 | *** *** |   |   | 6.50 | *** *** |   | 3.40 |   |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts maturing in 2007*** |         |                                     |         | *** ***                            |       |   |   | *** *** |   |   |   | *** *** |   |   |   |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| *Swaps*                          |         |                                     |         | *** ***                            |       |   |   | *** *** |   |   |   | *** *** |   |   |   |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| Receive variable/pay fixed       |         |                                     | Natural gas  | *** ***                            |       |   | 66,117,198 | *** *** |   |   | 7.12 | *** *** |   | 7.58 |   |   | 18.2 | *** *** |   |   | (47.8 | ) |   |   | 112.0 | *** *** |   |   | (1.0 | ) |   |
|                                  |         |                                     | NGL          | *** ***                            |       |   | 99,645 | *** *** |   |   | 38.41 | *** *** |   | 43.65 |   |   | — | *** *** |   |   | (0.5 | ) |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay  variable      |         |                                     | Natural gas  | *** ***                            |       |   | 65,858,920 | *** *** |   |   | 7.32 | *** *** |   | 7.46 |   |   | 41.2 | *** *** |   |   | (49.7 | ) |   |   | 0.5 | *** *** |   |   | (170.0 | ) |   |
|                             |         |                                     | NGL          | *** ***                            |       |   | 4,296,415 | *** *** |   |   | 38.18 | *** *** |   | 40.35 |   |   | 13.4 | *** *** |   |   | (22.4 | ) |   |   | — | *** *** |   |   | (22.5 | ) |   |
|                             |         |                                     | Crude oil    | *** ***                            |       |   | 388,680 | *** *** |   |   | 42.05 | *** *** |   | 68.02 |   |   | — | *** *** |   |   | (9.7 | ) |   |   | — | *** *** |   |   | (7.9 | ) |   |
| Receive variable/pay variable    |         |                                     | Natural gas  | *** ***                            |       |   | 15,959,366 | *** *** |   |   | 7.51 | *** *** |   | 7.50 |   |   | 1.0 | *** *** |   |   | (0.8 | ) |   |   | 0.7 | *** *** |   |   | (0.1 | ) |   |
| *Options*                        | * *     |                                     | * *     | *** ***                            |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                  |         |                                     | Natural gas  | *** ***                            |       |   | 365,000 | *** *** |   |   | 7.67 | *** *** |   | 4.31 |   |   | — | *** *** |   |   | (1.2 | ) |   |   | — | *** *** |   |   | (2.0 | ) |   |
| Puts                             |         |                                     | Natural gas  | *** ***                            |       |   | 365,000 | *** *** |   |   | 7.67 | *** *** |   | 3.40 |   |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts maturing in 2008*** |         |                                     |         | *** ***                            |       |   |   | *** *** |   |   |   | *** *** |   |   |   |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| *Swaps*                          |         |                                     |         | *** ***                            |       |   |   | *** *** |   |   |   | *** *** |   |   |   |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| Receive variable/pay fixed       |         |                                     | Natural gas  | *** ***                            |       |   | 16,668,457 | *** *** |   |   | 7.60 | *** *** |   | 7.35 |   |   | 9.7 | *** *** |   |   | (5.8 | ) |   |   | 18.5 | *** *** |   |   | — |   |   |
| Receive fixed/pay  variable      |         |                                     | Natural gas  | *** ***                            |       |   | 24,087,303 | *** *** |   |   | 6.27 | *** *** |   | 8.06 |   |   | 4.3 | *** *** |   |   | (44.0 | ) |   |   | — | *** *** |   |   | (66.3 | ) |   |
|                             |         |                                     | NGL          | *** ***                            |       |   | 1,607,253 | *** *** |   |   | 37.26 | *** *** |   | 40.90 |   |   | 2.1 | *** *** |   |   | (7.5 | ) |   |   | — | *** *** |   |   | (7.2 | ) |   |
|                             |         |                                     | Crude oil    | *** ***                            |       |   | 323,699 | *** *** |   |   | 44.18 | *** *** |   | 68.82 |   |   | — | *** *** |   |   | (7.3 | ) |   |   | — | *** *** |   |   | (5.2 | ) |   |
| Receive variable/pay variable    |         |                                     | Natural gas  | *** ***                            |       |   | 16,847,541 | *** *** |   |   | 8.25 | *** *** |   | 8.19 |   |   | 1.4 | *** *** |   |   | (0.5 | ) |   |   | 1.0 | *** *** |   |   | — |   |   |
| *Options*                        | * *     |                                     | * *     | *** ***                            |       |   | * * | *** *** |   |   | * * | *** *** |   | * * | * * |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                  |         |                                     | Natural gas  | *** ***                            |       |   | 366,000 | *** *** |   |   | 7.99 | *** *** |   | 4.31 |   |   | — | *** *** |   |   | (1.2 | ) |   |   | — | *** *** |   |   | (1.7 | ) |   |
| Puts                             |         |                                     | Natural gas  | *** ***                            |       |   | 366,000 | *** *** |   |   | 7.99 | *** *** |   | 3.40 |   |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
|                                  |              |                                          |              |                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

36

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|                                     | ** **   | **At September 30, 2006** | ** **  | **At December 31, 2005** | ** ** |
|-------------------------------------|--------------|------------------------------------------|-------------|-----------------------------------------|------------|
| ** **                          | ** **   | ** **                               | ** **  | ** **                              | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                          | ** **   | **Commodity**                            | ** **  | **Notional**(1)                         | ** ** | **  Receive  ** | ** ** | **  Pay  ** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **     Asset     ** | ** ** | **     Liability     ** | ** ** |
| ***Contracts maturing in 2009***    |         |                                     |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             | * *     |                                     |        |                                    |       |   |   |   |   |   |   |   | * * |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable/pay fixed          |         |                                     | Natural gas |                                    |       |   | 4,611,085 |   |   |   | 7.37 |   |   |   | 7.24 |   |   |   | 3.0 |   |   |   | (2.5 | ) |   |   | — |   |   |   | — |   |   |
| Receive fixed/pay  variable         |         |                                     | Natural gas |                                    |       |   | 12,865,240 |   |   |   | 5.15 |   |   |   | 7.78 |   |   |   | 1.0 |   |   |   | (30.5 | ) |   |   | — |   |   |   | (34.5 | ) |   |
|                                |         |                                     | NGL         |                                    |       |   | 1,407,075 |   |   |   | 41.05 |   |   |   | 41.08 |   |   |   | 1.3 |   |   |   | (1.4 | ) |   |   | — |   |   |   | (0.6 | ) |   |
|                                |         |                                     | Crude oil   |                                    |       |   | 191,625 |   |   |   | 55.63 |   |   |   | 67.40 |   |   |   | — |   |   |   | (2.0 | ) |   |   | — |   |   |   | (1.0 | ) |   |
| Receive variable/pay variable       |         |                                     | Natural gas |                                    |       |   | 16,277,500 |   |   |   | 8.02 |   |   |   | 7.97 |   |   |   | 1.2 |   |   |   | (0.5 | ) |   |   | 1.1 |   |   |   | — |   |   |
| *Options*                           | * *     |                                     |        |                                    |       |   |   |   |   |   |   |   | * * |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                     |         |                                     | Natural gas |                                    |       |   | 365,000 |   |   |   | 7.74 |   |   |   | 4.31 |   |   |   | — |   |   |   | (1.2 | ) |   |   | — |   |   |   | (1.4 | ) |   |
| Puts                                |         |                                     | Natural gas |                                    |       |   | 365,000 |   |   |   | 7.74 |   |   |   | 3.40 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
| ***Contracts maturing in 2010***    | *** *** |                                     |        |                                    |       |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             | * *     |                                     |        |                                    |       |   |   |   |   |   |   |   | * * |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable/pay fixed          |         |                                     | Natural gas |                                    |       |   | 761,950 |   |   |   | 7.59 |   |   |   | 3.80 |   |   |   | 2.4 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
| Receive fixed/pay  variable         |         |                                     | Natural gas |                                    |       |   | 9,490,000 |   |   |   | 4.11 |   |   |   | 7.51 |   |   |   | 0.1 |   |   |   | (26.9 | ) |   |   | 0.1 |   |   |   | (25.9 | ) |   |
|                                |         |                                     | NGL         |                                    |       |   | 317,550 |   |   |   | 30.60 |   |   |   | 34.20 |   |   |   | — |   |   |   | (0.9 | ) |   |   | — |   |   |   | (0.4 | ) |   |
|                                |         |                                     | Crude oil   |                                    |       |   | 146,000 |   |   |   | 61.04 |   |   |   | 65.62 |   |   |   | — |   |   |   | (0.5 | ) |   |   | — |   |   |   | (0.1 | ) |   |
| Receive variable/pay variable       |         |                                     | Natural gas |                                    |       |   | 7,200,000 |   |   |   | 8.35 |   |   |   | 8.26 |   |   |   | 0.7 |   |   |   | (0.2 | ) |   |   | — |   |   |   | — |   |   |
| *Options*                           | * *     |                                     |        |                                    |       |   |   |   |   |   |   |   | * * |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                     |         |                                     | Natural gas |                                    |       |   | 365,000 |   |   |   | 7.55 |   |   |   | 4.31 |   |   |   | — |   |   |   | (1.1 | ) |   |   | — |   |   |   | (1.1 | ) |   |
| Puts                                |         |                                     | Natural gas |                                    |       |   | 365,000 |   |   |   | 7.55 |   |   |   | 3.40 |   |   |   | 0.1 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
| ***Contracts maturing after 2010*** |         |                                     |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |         |                                     |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable/pay fixed          |         |                                     | Natural gas |                                    |       |   | 912,000 |   |   |   | 7.61 |   |   |   | 3.57 |   |   |   | 2.9 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
| Receive fixed/pay  variable         |         |                                     | Natural gas |                                    |       |   | 9,408,500 |   |   |   | 3.62 |   |   |   | 7.56 |   |   |   | — |   |   |   | (29.1 | ) |   |   | — |   |   |   | (26.1 | ) |   |
|                                |         |                                     | Crude oil   |                                    |       |   | 109,500 |   |   |   | 62.95 |   |   |   | 64.04 |   |   |   | — |   |   |   | (0.1 | ) |   |   | — |   |   |   | — |   |   |
| *Options*                           |         |                                     |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                     |         |                                     | Natural gas |                                    |       |   | 365,000 |   |   |   | 7.40 |   |   |   | 4.31 |   |   |   | — |   |   |   | (1.0 | ) |   |   | — |   |   |   | (0.9 | ) |   |
| Puts                                |         |                                     | Natural gas |                                    |       |   | 365,000 |   |   |   | 7.40 |   |   |   | 3.40 |   |   |   | 0.1 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |

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(1)**                **Volumes of Natural gas are measured inMMBtu, whereas volumes of NGL and Crude are measured in Barrels, or Bbl.

(2)**                **Weighted average prices received and paidare in $/MMBtu for Natural gas and in $/Bbl for NGL and Crude.

(3)**                **The fair value is determined based onquoted market prices at September 30, 2006 and December 31, 2005,respectively, discounted using the swap rate for the respective periods toconsider the time value of money. Fair values are presented in millions ofdollars.

***Accounting Treatment***

All derivative financial instruments are recorded inthe consolidated financial statements at fair market value and are adjustedeach period for changes in the fair market value (“mark-to-market”).The fair market value of these derivative financial instruments reflects theestimated amounts that we would pay or receive, other than in a forced or liquidationsale, to terminate or close the contracts at the reporting date, taking intoaccount the current unrealized losses or gains on open contracts. We useactively traded external market quotes and indices to value substantially allof the financial instruments we utilize.

Under the guidance of Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities* (“SFAS No. 133”),if a derivative financial instrument does not qualify as a hedge, or is notdesignated as a hedge, the derivative is adjusted to its fair market value, ormarked-to-market, each period with the increases and decreases infair value recorded as increases and decreases in Cost of natural gas in ourConsolidated Statements of Income. Cash flow is only impacted to the extent theactual derivative contract is settled by making or receiving a payment to orfrom the counterparty or by making or receiving a payment for entering into acontract that exactly offsets the original derivative contract. Typically, wesettle our derivative contracts when the physical transaction that underliesthe derivative financial instrument occurs.

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If a derivative financialinstrument qualifies and is designated as a cash flow hedge, a hedge of aforecasted transaction or future cash flows, any unrealized mark-to-market gainor loss is deferred in Accumulated other comprehensive income (“OCI”), acomponent of Partners’ Capital, until the underlying hedged transaction occurs.To the extent that the hedge instrument is effective in offsetting thetransaction being hedged, there is no impact to the income statement. Atinception and on a quarterly basis, we formally assess whether the hedgecontract is highly effective in offsetting changes in cash flows of hedged items.Any ineffective portion of a cash flow hedge’s change in fair market value isrecognized each period in earnings. Realized gains and losses on derivativefinancial instruments that are designated as hedges and qualify for hedgeaccounting are included in Cost of natural gas in the period the hedgedtransaction occurs. Gains and losses deferred in OCI related to cash flowhedges for which hedge accounting has been discontinued, remain in OCI untilthe underlying physical transaction occurs unless it is probable that theforecasted transaction will not occur by the end of the originally specifiedtime period or within an additional two-month period of time thereafter.Generally, our preference is for our derivative financial instruments toreceive hedge accounting treatment whenever possible, to mitigate the non-cashearnings volatility that arises under mark-to-market accountingtreatment. To qualify for cash flow hedge accounting as set forth in SFAS No. 133,very specific requirements must be met in terms of hedge structure, hedgeobjective and hedge documentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have four primary transaction types where the hedge structure doesnot meet the requirements to apply hedge accounting and, therefore, thesederivative financial instruments do not qualify for hedge accounting under SFASNo. 133 and are referred to as “non-qualified.” These non-qualifiedderivative financial instruments are marked-to-market each periodwith the change in fair value, representing unrealized gains and losses,included in Cost of natural gas in our Consolidated Statements of Income. Thesemark-to-market adjustments produce a degree of earnings volatilitythat can often be significant from period to period, but have no cash flowimpact relative to changes in market prices. The cash flow impact occurs whenthe underlying physical transaction takes place in the future and when theassociated financial instrument contract settlement is made.

The four primarytransaction types that do not qualify for hedge accounting are as follows:

1.                **Transportation—****In** our Marketingsegment, when we transport natural gas from one location to another the pricingindex used for natural gas sales is usually different from the pricing indexused for natural gas purchases, which exposes us to market price risk relativeto changes in those two indices. By entering into a basis swap, where we exchangeone pricing index for another, we can effectively lock in the margin,representing the difference between the sales price and the purchase price, onthe combined natural gas purchase and natural gas sale, removing any marketprice risk on the physical transactions. Although this represents a soundeconomic hedging strategy, the derivative financial instruments (i.e., thebasis swaps) we use to manage the commodity price risk associated with thesetransportation contracts do not qualify for hedge accounting under SFAS No. 133,since only the future margin has been fixed and not the future cash flow. As aresult, these derivative financial instruments are marked-to-market.

2.                **Storage—**In our Marketing segment, we use derivativefinancial instruments (i.e., natural gas swaps) to hedge the relativedifference between the injection price paid to purchase and store natural gasand the withdrawal price at which the natural gas is sold from storage. Theintent of these derivative financial instruments is to lock in the margin,representing the difference between the price paid for the natural gas injectedand the price received upon withdrawal of the gas from storage in a futureperiod. We do not pursue cash flow hedge accounting treatment for these storagetransactions since the underlying forecasted injection or withdrawal of naturalgas 

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may not occur in theperiod as originally forecast. This can occur because we have the flexibilityto make changes in the underlying injection or withdrawal schedule, givenchanges in market conditions. In addition, since the physical natural gas isrecorded at the lower of cost or market, timing differences can result when thederivative financial instrument is settled in a period that is different fromwhen the physical natural gas is sold from storage. As a result, derivativefinancial instruments associated with our natural gas storage activities cancreate volatility in our earnings.

3.                **Natural Gas Collars—**In our Natural Gas segment, we hadpreviously entered into natural gas collars to hedge the sales price of naturalgas. The natural gas collars were based on a NYMEX price, while the physicalgas sales were based on a different index. To better align the index of thenatural gas collars with the index of the underlying sales, we de-designatedthe original cash flow hedging relationship with the intent ofcontemporaneously re-designating the natural gas collars as hedges offorecasted physical natural gas sales with a NYMEX pricing index to bettermatch the indices. However, because the fair value of these derivativeinstruments was a liability to us at re-designation, they are considerednet written options under SFAS No. 133 and do not qualify for hedgeaccounting. These derivatives are being marked-to-market, with thechanges in fair value from the date of de-designation recorded toearnings each period. As a result, our operating income will be subject togreater volatility due to movements in the prices of natural gas until theunderlying long-term transactions are settled.

4.                **Optional Natural Gas Processing Volumes—**In our Natural Gassegment we use derivative financial instruments to hedge the volumes of NGLsproduced from our natural gas processing facilities. Our natural gas contractsallow us the option of processing natural gas when it is economical, andceasing to do so when processing becomes uneconomic. We have entered intoderivative financial instruments to fix the sales price of a portion of theNGLs that we produce at our discretion and to fix the associated purchases ofnatural gas required for processing. We will designate derivative financialinstruments associated with NGLs we produce at our discretion as cash flowhedges when the processing of natural gas is probable of occurrence. However,we are precluded from designating the derivative financial instruments enteredto manage the respective commodity price risk when we are unable to accuratelyforecast the NGLs to be processed at our discretion. As a result, our operatingincome will be subject to increased volatility due to fluctuations in NGLprices until the underlying transactions are settled or offset.

In each of the instances described above, theunderlying physical purchase, storage and sale of natural gas and NGLs areaccounted for on a historical cost or market basis rather than on themark-to-market basis we utilize for the derivative financial instrumentsemployed to mitigate the commodity price risk associated with our storage andtransportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair marketvalue while the physical transactions are recorded at historical cost) canand has resulted in volatility in our reported net income, even though theeconomic margin is essentially unchanged from the date the transactions wereconsummated.

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The following tablepresents the mark-to-market gains and losses associated with changes in thefair value of our commodity price derivative financial instruments, which arerecorded as an element of Cost of natural gas in our Consolidated Statements ofIncome and disclosed as a reconciling item on our Statements of Cash Flows:

| ** **                                                   | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                           | ** ** | **   2006   **        | ** ** | **   2005   ** | ** ** | **   2006   ** | ** ** | **   2005   ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                               | ** ** |
| Natural Gas segment                                          |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Hedge ineffectiveness                                        |       |                                                 | $          | (1.4                                                | )          |   |   | $ | 0.1 |   |   |   | $ | (1.5 | ) |   |   | $ | (1.9 | ) |   |
| Non-qualified hedges                                         |       |                                                 | 3.2        |                                                |       |   | (9.6 | ) |   |   | 1.4 |   |   |   | (20.7 | ) |   |
| Marketing                                                    |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                                 | 21.9       |                                                |       |   | (43.1 | ) |   |   | 53.2 |   |   |   | (37.8 | ) |   |
| Discontinued hedges                                          |       |                                                 | —     |                                                |       |   | — |   |   |   | — |   |   |   | (9.0 | ) |   |
| Derivative fair value  gains (losses)                        |       |                                                 | $          | 23.7                                                |       |   |   | $ | (52.6 | ) |   |   | $ | 53.1 |   |   |   | $ | (69.4 | ) |   |
|                                                              |            |                                                      |            |                                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

We record the change in fair value of our cash flowhedges in OCI until the derivative financial instruments are settled, at whichtime they are reclassified from OCI to earnings. Also included in OCI areunrecognized losses of approximately $5.6 million associated with cashflow hedges that were subsequently de-designated. These losses are reclassifiedto earnings over the periods during which the originally hedged forecastedtransactions affect earnings. For the three and nine months ended September 30,2006, we reclassified losses of $24.0 million and $63.7 million, respectively,from OCI to Cost of natural gas on our Consolidated Statements of Income forthe fair value of derivative financial instruments that were settled.

Ourderivative financial instruments are included at their fair values in theConsolidated Statements of Financial Position as follows:

| ** **                   | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**       | ** ** |
| Other current  assets        |       |                         | $          | 5.9                         |       |   |   | $ | 5.8 |   |   |
| Other assets, net            |       |                         | 5.9        |                        |       |   | 4.2 |   |   |
| Accounts payable  and other  |       |                         | (64.2      | )                           |       |   | (129.2 | ) |   |
| Other long-term  liabilities |       |                         | (161.3     | )                           |       |   | (243.0 | ) |   |
|                         |       |                         | $          | (213.7                      | )          |   |   | $ | (362.2 | ) |   |

 

The decrease in our obligation associated withderivative activities is primarily due to the decline in current and forwardnatural gas prices from December 31, 2005 to September 30, 2006. ThePartnership’s portfolio of derivative financial instruments is largelycomprised of long-term fixed price natural gas sales and purchaseagreements.

We do not requirecollateral or other security from the counterparties to our derivativefinancial instruments, all of which were rated “BBB+” or better by the majorcredit rating agencies.

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**Item 4.**                        Controlsand Procedures

The Partnership and Enbridge maintain systems ofdisclosure controls and procedures designed to provide reasonable assurancethat we are able to record, process, summarize and report the informationrequired in our annual and quarterly reports under the Securities Exchange Actof 1934. Our management has evaluated the effectiveness of our disclosurecontrols and procedures as of September 30, 2006. Based upon thatevaluation, our principal executive officer and principal financial officerconcluded that our disclosure controls and procedures are effective toaccomplish their purpose. In conducting this assessment, our management reliedon similar evaluations conducted by employees of Enbridge affiliates whoprovide certain treasury, accounting and other services on our behalf. Nochanges in our internal control over financial reporting were made during thenine months ended September 30, 2006, that would materially affect ourinternal control over financial reporting, nor were any corrective actions withrespect to significant deficiencies or material weaknesses necessary subsequentto that date.

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**PART II—OTHERINFORMATION**

**Item 1.**                        LegalProceedings

Refer to Part I,Item 1. Financial statements, Note 9, which is incorporated herein byreference.

**Item 1A.**                RiskFactors

The risk factors presented below update and should beconsidered in addition to the risk factors previously disclosed in our AnnualReport on Form 10-K for the fiscal year ended December 31,2005.

***Our partnershipagreement and the delegation of control agreement limit the fiduciary dutiesthat Enbridge Management and our general partner owe to our unitholders andrestrict the remedies available to our unitholders for actions taken byEnbridge Management and our general partner that might otherwise constitute abreach of a fiduciary duty.***

Our partnershipagreement contains provisions that modify the fiduciary duties that our generalpartner would otherwise owe to our unitholders under state fiduciary duty law.Through the delegation of control agreement, these modified fiduciary dutiesalso apply to Enbridge Management as the delegate of our general partner. Forexample, our partnership agreement:

·       permits our general partnerto make a number of decisions, including the determination of which factors itwill consider in resolving conflicts of interest, in its “sole discretion.”This entitles our general partner to consider only the interests and factorsthat it desires, and it has no duty or obligation to give consideration to anyinterest of, or factors affecting, us, our affiliates or any unitholder;

·       provides that any standardof care and duty imposed on our general partner will be modified, waived orlimited as required to permit our general partner to act under our partnershipagreement and to make any decision pursuant to the authority prescribed in ourpartnership agreement, so long as such action is reasonably believed by thegeneral partner to be in our best interests; and

·       provides that our generalpartner and its directors and officers will not be liable for monetary damagesto us or our unitholders for any acts or omissions if they acted in good faith.

These and similar provisions in our partnershipagreement may restrict the remedies available to our unitholders for actionstaken by Enbridge Management or our general partner that might otherwiseconstitute a breach of a fiduciary duty.

***Potential conflictsof interest may arise among Enbridge and its shareholders, on the one hand, andus and our unitholders and Enbridge Management and its shareholders, on theother hand. Because the fiduciary duties of the directors of our generalpartner and Enbridge Management have been modified, the directors may bepermitted to make decisions that benefit Enbridge and its shareholders orEnbridge Management and its shareholders more than us and our unitholders.***

Conflicts ofinterest may arise from time to time among Enbridge and its shareholders, onthe one hand, and us and our unitholders and Enbridge Management and itsshareholders, on the other hand. Conflicts of interest may also arise from timeto time between us and our unitholders, on the one hand, and EnbridgeManagement and its shareholders, on the other hand. In managing and controllingus as the delegate of our general partner, Enbridge Management may consider theinterests of all parties to a conflict and may resolve those conflicts bymaking decisions that benefit Enbridge and its shareholders or EnbridgeManagement and its shareholders more than us and our unitholders. The followingdecisions, among others, could involve conflicts of interest:

·       whether we or Enbridge Inc.will pursue certain acquisitions or other business opportunities;

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·       whether we will issueadditional units or other equity securities or whether we will purchaseoutstanding units;

·       whether Enbridge Managementwill issue additional shares;

·       the amount of payments toEnbridge and its affiliates for any services rendered for our benefit;

·       the amount of costs thatare reimbursable to Enbridge Management or Enbridge and its affiliates by us;

·       the enforcement ofobligations owed to us by Enbridge Management, our general partner or Enbridge,including obligations regarding competition between Enbridge and us; and

·       the retention of separatecounsel, accountants or others to perform services for us and EnbridgeManagement.

In these and similar situations, any decision byEnbridge Management may benefit one group more than another, and in making suchdecisions, Enbridge Management may consider the interests of all groups, aswell as other factors, in deciding whether to take a particular course ofaction.

In othersituations, Enbridge may take certain actions, including engaging in businessesthat compete with us, that are adverse to us and our unitholders. For example,although Enbridge and its subsidiaries are generally restricted from engagingin any business that is in direct material competition with our businesses,that restriction is subject to the following significant exceptions:

·       Enbridge and itssubsidiaries are not restricted from continuing to engage in businesses, includingthe normal development of such businesses, in which they were engaged at thetime of our initial public offering in December 1991;

·       such restriction is limitedgeographically only to those routes and products for which we providedtransportation at the time of our initial public offering;

·       Enbridge and itssubsidiaries are not prohibited from acquiring any business that materially anddirectly competes with us as part of a larger acquisition, so long as themajority of the value of the business or assets acquired, in Enbridge’sreasonable judgment, is not attributable to the competitive business; and

·       Enbridge and itssubsidiaries are not prohibited from acquiring any business that materially anddirectly competes with us if that business is first offered for acquisition tous and the board of directors of Enbridge Management and our unitholdersdetermine not to pursue the acquisition.

Since we were not engaged in any aspect of the naturalgas business at the time of our initial public offering, Enbridge and itssubsidiaries are not restricted from competing with us in any aspect of thenatural gas business. In addition, Enbridge and its subsidiaries would bepermitted to transport crude oil and liquid petroleum over routes that are notthe same as our Lakehead system, even if such transportation is in directmaterial competition with our business.

These exceptions alsoexpressly permitted the reversal by Enbridge in 1999 of one of its pipelinesthat extends from Sarnia, Ontario to Montreal, Quebec. As a result of thisreversal, Enbridge competes with us to supply crude oil to the Ontario, Canadamarket.

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**Item 6.**                        Exhibits

Eachexhibit identified below is filed as part of this document. Exhibits notincorporated by reference to a prior filing are designated by an “*”; allexhibits not so designated are incorporated herein by reference to a previousfiling as indicated.
| 3.1   |   | Certificate of Limited Partnership of the  Partnership (incorporated by reference to Exhibit 3.1 to the  Partnership’s Registration Statement No. 33-43425).                                                                                |
|-------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2   |   | Certificate of Amendment  to Certificate of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.2 to the Partnership’s 2000 Form 10-K/A  dated October 9, 2001).                                           |
| 3.3   |   | Third Amended and  Restated Agreement of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.1 to the Partnership’s Quarterly Report on  Form 10-Q filed November 14, 2002).                               |
| 3.4   |   | Fourth Amended and  Restated Agreement of Limited Partnership of the Partnership, dated  August 15, 2006 (incorporated by reference to Exhibit 3.1 of our  Current Report on Form 8-K dated August 16, 2006).                          |
| 4.1   |   | Form of Certificate  representing Class A Common Units (incorporated by reference to Exhibit 4.1  to the Partnership’s 2000 Form 10-K/A dated October 9, 2001).                                                              |
| 4.2   |   | Registration Rights  Agreement, dated August 15, 2006, between Enbridge Energy Partners, L.P.  and CDP Infrastructures Fund G.P. (incorporated by reference to  Exhibit 4.1 of our Current Report on Form 8-K dated  August 16, 2006). |
| 31.1* |   | Certification of  Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                        |
| 31.2* |   | Certification of  Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                        |
| 32.1* |   | Certification of  Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                        |
| 32.2* |   | Certification of  Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                        |

 

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.

|                              |     | **ENBRIDGE ENERGY PARTNERS, L.P.**                                    |
|------------------------------|----------|-----------------------------------------------------------------------|
|                         |     | (Registrant)                                                          |
|                         | By:      | Enbridge Energy  Management, L.L.C.                                   |
|                         |     | as delegate of Enbridge Energy Company, Inc.  as General Partner |
| Date:  October 30, 2006 | By:      | /s/ STEPHEN J. J. LETWIN                                              |
|                         |     | Stephen J.J. Letwin                                                   |
| * *                     | * * | *Managing Director*                                                   |
| * *                     | * * | *(Principal Executive Officer)*                                       |
| Date:  October 30, 2006 | By:      | /s/ MARK A. MAKI                                                      |
| * *                     | * * | Mark A. Maki                                                          |
| * *                     | * * | *Vice President, Finance*                                             |
| * *                     | * * | *(Principal Financial Officer)*                                       |

 

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